WO2019241458A1

WO2019241458A1 - Defining a well completion program for an oil and gas well

Info

Publication number: WO2019241458A1
Application number: PCT/US2019/036871
Authority: WO
Inventors: Dmitriy Ivanovich Potapenko
Original assignee: Schlumberger Technology Corporation; Schlumberger Canada Limited; Services Petroliers Schlumberger; Schlumberger Technology B.V.
Priority date: 2018-06-13
Filing date: 2019-06-13
Publication date: 2019-12-19

Abstract

Apparatus and methods for defining an optimal well completion program for an oil and gas well. An example method includes defining candidate well completion programs for the well. Each candidate well completion program includes hydraulic fracturing of the well. Each candidate well completion program differs with respect to at least one well completion parameter. At least one of the candidate well completion programs includes forming extended perforation tunnels extending into a formation surrounding the well. The method also includes defining an evaluation criteria for evaluating the candidate well completion programs, forecasting results of the candidate well completion programs with respect to the defined evaluation criteria, comparing the forecasted results of the candidate well completion programs with respect to the defined evaluation criteria, and defining an optimal one of the candidate well completion programs based on the comparison of the forecasted results.

Description

DEFINING A WELL COMPLETION PROGRAM FOR AN OIL AND GAS

WELL

Cross-Reference to Related Applications

[0001] This application claims priority to and the benefit of U.S. Provisional Application No. 62/684,254, titled“DEFINING A WELL COMPLETION PROGRAM FOR AN OIL AND GAS WELL,” filed June 13, 2018, the entire disclosure of which is hereby incorporated herein by reference.

Background of the Disclosure

[0002] Wellbores are drilled through subterranean formations for the extraction of hydrocarbons. Hydraulic fracturing (“frac”) is an efficient way of increasing productivity of wells in oil and gas bearing formations. Hydraulic fracturing is based on pumping fracturing fluid at high pressure into the wellbore to create localized fractures in the formation to increase the production rates of hydrocarbons. The fracturing 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.

[0003] 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

[0004] 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. [0005] The present disclosure introduces a method including defining candidate well completion programs for a well. Each candidate well completion program includes hydraulic fracturing of the well. Each candidate well completion program differs with respect to at least one well completion parameter. At least one of the candidate well completion programs includes forming extended perforation tunnels extending into a formation surrounding the well. The method also includes defining an evaluation criteria for evaluating the candidate well completion programs, forecasting results of the candidate well completion programs with respect to the defined evaluation criteria, comparing the forecasted results of the candidate well completion programs with respect to the defined evaluation criteria, and defining an optimal one of the candidate well completion programs based on the comparison of the forecasted results.

[0006] The present disclosure also introduces a method including defining candidate well completion programs for a well, where each candidate well completion program includes hydraulic fracturing of the well, each candidate well completion program differs with respect to at least one well completion parameter, at least one of the candidate well completion programs includes forming extended perforation tunnels extending into a formation surrounding the well, and at least one of the well completion parameters is a parameter of one or more of the extended perforation tunnels. The method also includes defining an evaluation criteria for evaluating the candidate well completion programs, forecasting results of the candidate well completion programs with respect to the defined evaluation criteria, comparing the forecasted results of the candidate well completion programs with respect to the defined evaluation criteria, and defining an optimal one of the candidate well completion programs based on the comparison of the forecasted results.

[0007] 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

[0008] 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. [0009] FIG. l 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.

[0010] FIG. 2 is a graph related to one or more aspects of the present disclosure.

[0011] FIG. 3 is a schematic view of a portion of a wellbore related to one or more aspects of the present disclosure.

[0012] FIG. 4 is a schematic view of a portion of a wellbore related to one or more aspects of the present disclosure.

[0013] 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.

[0014] 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.

[0015] FIG. 7 is a schematic view of a portion the apparatus shown in FIG. 6 in a different stage of operation.

[0016] FIG. 8 is a schematic view of the apparatus shown in FIGS. 6 and 7 in a different stage of operation.

[0017] FIG. 9 is a schematic view of the apparatus shown in FIGS. 6-8 in a different stage of operation.

[0018] FIG. 10 is a schematic view of the apparatus shown in FIGS. 6-9 in a different stage of operation.

[0019] 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.

[0020] 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.

[0021] 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.

[0022] 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.

[0023] 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.

[0024] FIG. 16 is a schematic view of the apparatus shown in FIG. 15 in a different stage of operation. [0025] FIG. 17 is a schematic view of the apparatus shown in FIGS. 15 and 16 in a different stage of operation.

[0026] FIG. 18 is a schematic view of the apparatus shown in FIGS. 15-17 in a different stage of operation.

[0027] 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.

[0028] 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.

[0029] 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.

[0030] 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.

[0031] FIG. 23 is a schematic view of the apparatus shown in FIG. 22 in a different stage of operation.

[0032] FIG. 24 is a schematic view of the apparatus shown in FIGS. 22 and 23 in a different stage of operation.

[0033] FIG. 25 is a schematic sectional view of at least a portion of an example

[0034] FIG. 26 is a schematic sectional view of at least a portion of an example

[0035] FIG. 27 is a schematic sectional view of at least a portion of an example

[0036] FIG. 28 is a schematic sectional view of at least a portion of an example

[0037] FIG. 29 is a schematic sectional view of at least a portion of an example

[0038] FIG. 30 is a schematic sectional view of at least a portion of an example

[0039] 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.

[0040] 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. [0041] FIG. 33 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.

[0042] FIG. 34 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.

[0043] FIG. 35 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.

[0044] FIG. 36 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.

[0045] FIG. 37 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.

[0046] FIG. 38 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.

[0047] FIGS. 39-42 are graphs according to one or more aspects of the present disclosure.

[0048] FIG. 43 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.

Detailed Description

[0049] 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.

[0050] The systems and methods described herein generally relate to enhancing hydrocarbon fluid production. For example, a well may be created in a subterranean region by drilling a borehole (e.g., a generally vertical wellbore). In certain embodiments, at least one extended perforation tunnel may be created and oriented to extend outwardly from the borehole at least a certain amount (e.g., at least 10 feet, or 3.05 meters) into a formation surrounding the borehole.

In certain embodiments, the extended perforation tunnels may be created to extend outwardly from the borehole at least 5 feet (1.5 meters), at least 10 feet (3.05 meters), at least 15 feet (4.6 meters), at least 20 feet (6.1 meters), or even substantially longer than 20 feet (6.1 meters) (e.g., up to or even greater than 1,600 feet (488 meters), as described in greater detail herein). In certain embodiments, the borehole may be oriented generally vertically and the extended perforation tunnels may extend outwardly generally horizontally. However, certain

embodiments may utilize a deviated (e.g., at least partially horizontal) borehole with extended perforation tunnels extending outwardly from the deviated borehole. Depending on the application and characteristics of the subterranean region, the extended perforation tunnels may be oriented generally horizontally, generally vertically, or at any desired orientations

therebetween.

[0051] In general, as used herein, the term“extended perforation tunnel” is intended to mean a secondary borehole that extends from a main borehole at a substantially constant angle for at least 5 feet (1.5 meters), at least 10 feet (3.05 meters), at least 15 feet (4.6 meters), at least 20 feet (6.1 meters), or even substantially longer than 20 feet (6.1 meters) (e.g., up to or even greater than 1,600 feet (488 meters), as described in greater detail herein). Conventional lateral boreholes are typically created by gradually veering from a main borehole at a continually increasing angle (i.e., such that the main borehole and the lateral borehole generally form a curved intersection between the two). In contrast, the extended perforation tunnels described herein directly extend from a main borehole at a non-zero angle (e.g., contrary to conventional lateral boreholes that extend from a main borehole at an angle that gradually increases from 0 degrees). Indeed, the non-zero angle directly formed between an extended perforation tunnel and a corresponding main borehole may be an angle substantially greater than 0 degrees, such as greater than 20 degrees, greater than 30 degrees, greater than 45 degrees, greater than 60 degrees, between 60 degrees and 90 degrees, between 70 degrees and 90 degrees, or between 80 degrees and 90 degrees, as described in greater detail herein, As such, the extended perforation tunnels described herein are not connected to a main borehole by a curved intersection, contrary to conventional lateral boreholes. Rather, the extended perforation tunnels described herein form relatively sharp transitions from their respective main boreholes. As used herein, the term “substantially constant angle” is intended to mean an angle that varies along a length of an extended perforation tunnel by no more than a very small amount, such as 5 degrees, 4 degrees, 3 degrees, 2 degrees, 1 degree, or even less.

[0052] In certain applications, the orientation of the extended perforation tunnels may be selected such that each extended perforation tunnel extends at a desired angle with respect to a direction of principal stresses in the formation. For example, in certain applications, the tunnel azimuths may be oriented in a direction of maximum horizontal stress, minimum horizontal stress, or at a desired other angle with respect to the maximum horizontal stress. Additionally, the tunnel azimuths (as well as the borehole azimuth) may be relatively constant in certain applications, but they may also vary in other applications, for example, to achieve a desired positioning with respect to a hydrocarbon bearing target zone in a formation.

[0053] Once the extended perforation tunnels are created, a fracture stimulation of the extended perforation tunnels may be performed to create a network of fractures. For example, a hydraulic fracturing fluid may be pumped downhole and out through the extended perforation tunnel (or extended perforation tunnels) to create fracture networks extending from each extended perforation tunnel. The fracture networks may be created to extend laterally from each extended perforation tunnel, but they also may be created parallel with the extended perforation tunnels and/or at other desired orientations. In general, the orientation of the extended perforation tunnels ensures that the network of fractures extends through a target zone in a hydrocarbon bearing region of the formation.

[0054] FIG. 1 depicts a drilling rig 20 of a well construction system 10 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.

[0055] 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.

[0056] 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 extended perforation tunnels 46 ( e.g ., tunnels, laterals, lateral tunnels, sidetracks, radials) extending radially or otherwise 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. Several terms may be used herein to describe or refer to extended perforation tunnels formed or otherwise extending from a wellbore, including“tunnels”,“laterals”, and“lateral tunnels”. Each of these terms is to be considered equivalent within the scope of the present disclosure and can be used interchangeably.

[0057] One or more of the substantially vertical wellbore 42, the deviated wellbore 44, and/or one or more of the extended perforation tunnels 46 may be at least partially lined with a casing 43 and/or open-hole. The extended perforation 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 extended perforation tunnels 46 (whether the extended perforation 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.

[0058] 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.

[0059] 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 (Met) 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. [0060] 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.

[0061] 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. Although the data depicted in FIG. 2 is 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).

[0062] 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).

[0063] 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.

[0064] The present disclosure introduces the realization that production efficiency may be enhanced via drilling and fracturing a wellbore system that includes a plurality of extended perforation 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 extended perforation 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 extended perforation tunnels.

[0065] 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 extended perforation tunnels are drilled or otherwise formed (104), each extending from the deviated wellbore. The extended perforation tunnels may be substantially vertical, in that the extended perforation 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 extended perforation tunnels are then fractured (106). Although the implementations described herein are not limited to a particular plurality of extended perforation tunnels, it will be understood that increasing the number of extended perforation 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) extended perforation tunnels extending from each deviated wellbore. [0066] 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.

[0067] 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 extended perforation 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 extended perforation tunnels.

[0068] Referring to FIGS. 1 and 5, collectively, the extended perforation tunnels 46 may be fractured (106) sequentially or simultaneously. For example, a first extended perforation tunnel 46 may be drilled (104) and then fractured (106) using a FWD tool. A second extended perforation 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 extended perforation 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 extended perforation tunnels may first be drilled (104), and the extended perforation tunnels may then be fractured (106) using a single- stage or multi-stage fracturing operation in which multiple extended perforation tunnels are fractured in each stage.

[0069] The extended perforation 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 extended perforation tunnels 46. After drilling the deviated wellbore 44 to its final length, the extended perforation 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 extended perforation 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 extended perforation tunnel 46. The deviated wellbore 44 may then be extended and the wellbore steered to drill a subsequent extended perforation tunnel 46. This process may continue such that a number of extended perforation tunnels 46 are drilled along an incrementally extended deviated wellbore 44. As described, the extended perforation tunnels 46 may be fractured sequentially or simultaneously. One such implementation is described in more detail below with respect to FIGS. 15-18.

[0070] 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). Although 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 extended perforation tunnel 272 may then be drilled, as depicted in FIG. 7. The first extended perforation 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 extended perforation tunnel, as depicted in FIG. 8.

[0071] After the first extended perforation tunnel 272 has been fractured, a second extended perforation 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 extended perforation tunnel 274 may then be fractured in the manner described above for the first extended perforation tunnel 272. As depicted in FIG. 11, a plurality of extended perforation tunnels 276 may be similarly drilled from the deviated wellbore 265 and fractured. The extended perforation 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 extended perforation 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 extended perforation 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 extended perforation tunnels 276 extending upward and downward (e.g., as depicted in FIG. 11). In the context of the present disclosure, an upward-pointing extended perforation 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), and a downward pointing extended perforation 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 extended perforation 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).

[0072] 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, extended perforation tunnels may be fractured without the entry of a fracturing tool into the extended perforation 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 extended perforation 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 extended perforation tunnels 308, as well as open-hole packers 314 deployed between adjacent ones of the extended perforation tunnels 308. The packers 314 may be expanded (as depicted) to fluidly isolate the individual extended perforation tunnels 308 from one another. The extended perforation 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 extended perforation tunnels 308. In this manner, a multi-stage fracturing operation may be utilized, in which the extended perforation 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 extended perforation 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 extended perforation tunnels 308 are formed and utilized to fracture or otherwise stimulate the surrounding formation.

[0073] It will be understood that the decision regarding whether to fracture adjacent extended perforation tunnels sequentially or simultaneously (and how many extended perforation 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 of formation zones, however, 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 selected formation 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).

[0074] 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 extended perforation tunnel 362, as shown in FIG. 15. After the first extended perforation tunnel 362 is drilled, the deviated wellbore 355 is extended and a second extended perforation tunnel 364 is drilled, as shown in FIG. 16. The deviated wellbore 355 may then be further extended and a third extended perforation tunnel 366 may be drilled, and then still further extended and a fourth extended perforation 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 extended perforation tunnels. For example, FIG. 18 depicts seven downward pointing extended perforation tunnels 360).

[0075] With further reference to FIGS. 15-18, the extended perforation tunnels 360 may be fractured sequentially or simultaneously as described above. For example, the extended perforation tunnels 360 may be fractured sequentially using an FWD tool as described above with respect to FIGS. 6-1 1. However, the extended perforation tunnels may be fractured using a multi-stage fracturing operation in which the extended perforation tunnels may be fractured one by one, in pairs, in triplets, or in other combinations, as described above with respect to FIGS. 12-14.

[0076] 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 (z.e., deviated or substantially horizontal pilot wells). Each deviated wellbore 354 includes upward and/or downward extending extended perforation 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 extended perforation tunnels 356A. The extended perforation 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 extended perforation 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 extended perforation tunnels 356 fractured.

[0077] FIG. 20 depicts another implementation of a wellbore system 370 including a plurality of fractured extended perforation 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 an extended perforation 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 extended perforation tunnel 376. Each extended perforation tunnel 376 may be fractured when drilling of that extended perforation 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 extended perforation tunnels 376 that may be fractured.

[0078] 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 extended perforation tunnels extending from the deviated wellbore portion, installing (116) a completion string in the deviated wellbore, and then stimulating (118) the extended perforation tunnels.

[0079] 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 extended perforation 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 extended perforation 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.

[0080] The length of the extended perforation tunnels may vary, such as between about 2 meters and about 200 meters. The extended perforation tunnels may be drilled using the same drilling tool that is used to drill the deviated wellbore, or the extended perforation 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 extended perforation 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 extended perforation 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 extended perforation 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. Patent No. 8,408,333, the entirety of which is hereby incorporated herein by reference. However, the extended perforation 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.

[0081] The extended perforation tunnels may be formed after the entire deviated wellbore is formed, or the extended perforation 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 extended perforation 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 extended perforation tunnel. The casing may or may not be cemented.

[0082] FIGS. 22-24 are schematic sectional views of a portion of an example implementation of a downhole radial drilling tool system disposed within a deviated wellbore and operable to from extended perforation 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 an extended perforation 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).

[0083] 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 perforation 418 (i.e., a hole) through the casing 404. When the perforation 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., a 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, through the deflection tool 410, and into alignment with or at least partially into the perforation 418. The hydraulic jetting tool 420 may then be operated to discharge a stream 424 of pressurized water or another fluid to form an extended perforation tunnel 422. However, instead of utilizing both the drilling tool 416 and the jetting tool 420, a combinatory radial drilling tool (not shown) may be utilized to form both the casing perforation 418 and the extended perforation tunnel 422, such as to minimize or reduce the number of lifting/tripping operations. After the extended perforation tunnel 422 is formed, the deflecting tool 410 may be reoriented to form another extended perforation 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 extended perforation tunnels 422 are formed along the entire deviated wellbore 402 or into several formation zones. Because the drilling and jetting tools 416, 420 or the combinatory radial drilling tool may be utilized to form the perforations 418 and the extended perforation tunnels 422 extending such perforations 418 into the formation, the extended perforation tunnels 422 formed by the drilling and jetting tools 416, 420 or the combinatory radial drilling tool may be referred to as“extended perforation tunnels.” [0084] 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 extended perforation tunnels 422.

Stimulation (e.g, fracturing) operations may be performed after the extended perforation 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 extended perforation tunnels 422 in one or more subsequent formation zones.

[0085] It is to be understood that other downhole tools may be utilized to form the extended perforation 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 extended perforation 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 extended perforation tunnel 422. After the extended perforation tunnel 422 is formed, the laser cutting tool 430 may be reoriented to form another extended perforation 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 extended perforation tunnels 422 are formed along the entire deviated wellbore 402 or into several formation zones.

[0086] 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 extended perforation 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 extended perforation 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 extended perforation tunnels 506 may extend in an upward direction and some of the extended perforation tunnels 506 extend in a downward direction. As further shown, some of the extended perforation tunnels 506 may extend into a first formation zone 512, some of the extended perforation tunnels 506 may extend into a second formation zone 514, and some of the extended perforation tunnels 506 may extend into a third formation zone 516.

[0087] 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 extended perforation 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 extended perforation tunnels 506 are formed and the casing string 518 may be installed after the extended perforation tunnels 506 are formed.

[0088] 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 extended perforation 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 extended perforation tunnels 506, such as may permit treatment fluid ( e.g ., fracturing fluid) to enter selected extended perforation 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 extended perforation tunnels 308. [0089] Referring again to FIGS. 26-28, one or more of the extended perforation 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 extended perforation tunnels 506, such as to control location and/or propagation of fractures along the extended perforation tunnels 506. The liners may be cemented in place or used open-hole.

[0090] 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 extended perforation tunnels and the other completion system may be installed after formation of the plurality of extended perforation 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.

[0091] 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 extended perforation tunnels 506 are formed, an inner casing string 534 may be installed within the outer casing string 532. The extended perforation 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 extended perforation 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 extended perforation 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 extended perforation tunnels 506 and, thus, selected one or more formation zones 512, 514, 516 during multi-stage fracturing treatment.

[0092] 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 extended perforation 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) utilizing perforating charges at locations adjacent the extended perforation tunnels 506, such as may permit treatment fluid ( e.g ., fracturing fluid) to enter selected one or more extended perforation 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.

[0093] 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 extended perforation 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 extended perforation 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.

[0094] 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 extended perforation 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 extended perforation tunnels may be stimulated sequentially from toe to heel by first perforating the casing string adjacent the selected extended perforation 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 extended perforation 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 extended perforation tunnels and formation zone(s) from extended perforation tunnels and formation zone(s) selected for subsequent treatment. The fracturing fluid may then be again pumped into the casing string to stimulate the extended perforation tunnels and the corresponding formation zone(s). Such process may be repeated until each of the intended formation zones are stimulated.

[0095] The rate of the fracturing fluid or another treatment fluid flowing into each extended perforation 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 extended perforation 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 extended perforation 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.

[0096] Although each deviated wellbore described herein is shown extending horizontally and each extended perforation 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.

[0097] 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 extended perforation tunnels 554 extending through a subterranean formation, according to one or more aspects of the present disclosure. It is to be understood that the extended perforation 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 extended perforation 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 extended perforation 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 extended perforation tunnels 554 extend from the deviated wellbore 552 with respect to the true vertical 558 may be formed in any direction (z.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 (z.e., is aligned with) an X- Y plane, the extended perforation 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).

[0098] 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 an extended perforation 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 extended perforation tunnels for optimal productivity.

[0099] Accordingly, as the hydraulic fractures propagate along the plane 578 of maximum horizontal formation stress 576, extended perforation tunnels within the scope of the present disclosure may be formed extending along (z.e., in alignment with, in direction of) a plane comprising the maximum horizontal formation stress. Such orientation of the extended perforation tunnel may result in a hydraulic fracture originating at the extended perforation tunnel propagating longitudinally along the extended perforation 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 extended perforation tunnel 580 may be formed at an angle 582 with respect to the true vertical 584 such that the extended perforation tunnel 580 extends along (z.e., is aligned with, extends in a direction 585 along) the plane 578 (along the X- Y plane) and not such that the extended perforation tunnel 580 extends through, across, or diagonally to the plane 578 (along the Y-Z plane). Such orientation 585 of the extended perforation tunnel 580 may result in a hydraulic fracture propagating longitudinally along the extended perforation tunnel 580 (not diagonally across the extended perforation tunnel 580), facilitating longitudinal and, thus, optimal fluid connection between the extended perforation tunnel 580 and the fracture.

[00100] The drilling and fracturing methods described herein may facilitate substantial production and efficiency gains in hydraulic fracturing operations. For example, use of the extended perforation tunnels within the scope of the present disclosure may substantially improve the efficiency of production, such as by promoting production from a greater number of sedimentary layers in the formation. Forming these extended perforation 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 extended perforation tunnel is capable of producing about one-third to one-half that of a fully fractured deviated wellbore having no extended perforation tunnels. The production gains may therefore be substantial when multiple extended perforation tunnels are used. For example, drilling and fracturing ten extended perforation 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 extended perforation tunnels resulting in production magnification.

[00101] Although a 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. For example, although the extended perforation tunnels ( e.g ., extended perforation 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 extended perforation 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 (z.e., angles ranging between about zero degrees and about 90 degrees from true horizontal 562). For example, one or more of the extended perforation 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 (z.e., ranging between about zero degrees and about 45 degrees from true horizontal 562), resulting in extended perforation tunnels that may be substantially horizontal or closer to true horizontal 562 than to true vertical 558. Accordingly, one or more extended perforation 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 extended perforation tunnels deviate from true vertical 558, one or more of the extended perforation tunnels within the scope of the present disclosure may extend along (z.e., be substantially aligned with) the plane 578 of maximum horizontal stress 576 of the subterranean formation, as described above.

[00102] Furthermore, although FIGS. 1-32 and the corresponding description collectively disclose apparatus and methods for forming extended perforation tunnels that extend

substantially vertically from a substantially horizontal or otherwise deviated portion of a wellbore, it is to be understood that the extended perforation tunnels within the scope of the present disclosure may also or instead be formed to extend radially or otherwise laterally from a substantially vertical portion of the wellbore.

[00103] The extended perforation tunnels ( e.g ., lateral tunnels) within the scope of the present disclosure may have lengths of about three meters (about ten feet) or more and may be formed by jetting or drilling laterally into a formation using radial drilling methodology. With reference to FIG. 33, the terms“lateral” and“laterally” as used herein, may infer that a tunnel is being formed at a predetermined angle 588 relative to a wellbore 586 that is characterized by deviation from the direction of the wellbore 586 and an azimuthal tangential angle 589. The angels 588, 589 may range between zero degrees and about 90 degrees.

[00104] FIG. 34 is a schematic sectional view of at least a portion of an example wellbore system 590 according to one or more aspects of the present disclosure comprising a substantially vertical wellbore portion 502 and a plurality of extended perforation tunnels 592 extending from such substantially vertical wellbore portion 502 through a casing string 508 and one or more formation zones of a subterranean formation. The extended perforation tunnels 592 may extend at selected angles 594, 596 with respect to the substantially vertical wellbore portion 502 and/or the true vertical and horizontal directions 558, 562. For example, assuming that the wellbore system 590 is formed in a three-dimensional space X-Y-Z, one or more of the extended perforation tunnels 592 may deviate or otherwise extend from the substantially vertical wellbore portion 502, along the X-Y plane and/or the Y-Z plane, at angles 594 ranging 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 substantially vertical wellbore portion 502 and/or the true vertical 558). However, angles 594 that are greater than -45 and 45 degrees from the true horizontal 562 are also within the scope of the present disclosure, resulting in extended perforation tunnels 592 that may be substantially vertical or closer to the true vertical 558 than to the true horizontal 562. Furthermore, one or more of the extended perforation tunnels 592 may also extend from the substantially vertical wellbore portion 502 and/or the true vertical 558 along the X-Z plane at any angle 596 (z.e., between zero and 360 degrees) or in any azimuthal direction 597 around the substantially vertical wellbore portion 502 and/or the true vertical 558. For example, the extended perforation tunnels 592 may be formed to extend from the substantially vertical wellbore portion 502 in a direction along or aligned with a plane of maximum horizontal formation stress ( e.g ., along direction 585 and plane 578, as shown in FIG. 32), which may result in a hydraulic fracture propagating longitudinally along the extended perforation tunnels 592. However, the extended perforation tunnels 592 may be formed to extend from the substantially vertical wellbore portion 502 in a direction that is transverse (z.e., perpendicular) to the plane of maximum horizontal formation stress, which may result in hydraulic fractures propagating transversely with respect to the extended perforation tunnels 592.

[00105] It is to be understood that the substantially vertical wellbore portion 502 and the extended perforation tunnels 592 shown in FIG. 34 and described above may be formed by one or more of the apparatus and methods shown in FIGS. 1-32 and described above, including the drilling tool 416 and the hydraulic jetting tool 420 shown in FIGS. 23 and 24. It is to be further understood that the substantially vertical wellbore portion 502 may be an open-hole wellbore portion that is not lined with a casing, such as the casing string 508. It is to be further understood that the substantially vertical wellbore portion 502 may also or instead contain other downhole equipment, such as a fracturing tool 310 and a plurality of fracturing sleeves 312, shown in FIGS. 10-14, blank pipes 524 and a plurality of open-hole packers 522, shown in FIG. 28, and a casing string 534 and a plurality of fracturing sleeves 536, shown in FIG. 29.

[00106] The present disclosure is further directed to a method of selecting or otherwise defining a program ( e.g ., plan, schedule) for completing an oil and gas well by utilizing hydraulic fracturing. The defined well completion program may include forming (e.g., drilling, cutting, etc.) extended perforation tunnels (e.g, extended perforation tunnels 46, 272, 276, 308, 360, 376, 422, 506, 554, 580, 592 described above and shown in FIGS. 1-34) extending from a wellbore (e.g, wellbore 42, 44, 255, 302, 352, 372, 402, 502, 552 described above and shown in FIGS. 1-34). The extended perforation tunnels may be utilized to control direction, location, and quantity of hydraulic fractures formed during hydraulic fracturing operations. The method may facilitate synergy between the extended perforation tunnel forming operations and hydraulic fracturing operations, such that the extended perforation tunnel forming operations and hydraulic fracturing operations fit (e.g, match, are harmonized with) each other. The extended perforation tunnels may comprise various orientations, extend through one or more formation zones, and may facilitate higher drainage radius. Forming extended perforation tunnels that do not match or that are not harmonized with planned hydraulic fracturing operations may result in non-optimal stimulation of corresponding reservoir(s) and may lead to multiple operational problems or issues related to treatment placement, safety, and environmental considerations. The method of defining the well completion program according to one or more aspects of the present disclosure minimizes such risks and maximizes collective effect of the extended perforation tunnels and hydraulic fracturing.

[00107] FIG. 35 is a flow-chart diagram of at least a portion of an example implementation of a method (120) for defining a program for completing an oil and gas well extending through a subterranean formation according to one or more aspects of the present disclosure. The method (120) may evaluate or consider use of at least a portion of one or more examples of one or more instances of the apparatus and/or methods described above and shown in one or more of FIGS. 1- 34. After the well completion program is defined, the defined well completion program may be implemented or performed at least in part by utilizing or otherwise in conjunction with at least a portion of one or more examples of one or more instances of the apparatus shown in one or more of FIGS. 1-34 and/or otherwise within the scope of the present disclosure. Accordingly, the following description refers to FIGS. 1-35, collectively. [00108] The method (120) may comprise selecting or otherwise defining (122) one or more candidate wells for completion, including via forming extended perforation tunnels and/or hydraulic fracturing. The candidate wells may be defined, for example, based on considerations related to logistics, reservoir quality, completion acceptance ( e.g ., pressure or pumping rate limitations), and economical feasibility. The method (120) may further comprise selecting or otherwise defining (124) a criteria for comparing or otherwise evaluating candidate well completion programs (i.e., well completion program scenarios) for one or more of the selected (i.e., target) candidate wells. The evaluation criteria may be defined, for example, based on economic considerations (e.g., NPV, IRR, IPB, payback time, etc.), production targets (e.g, cumulative production projections), and targets for operational efficiency. The method (120) may further comprise selecting or otherwise defining (126) candidate formation zones into or through which the extended perforation tunnels may be formed along or otherwise extending from a wellbore. Location of the extended perforation tunnels may be defined based on geomechanical and/or petrophysical logs. For example, the extended perforation tunnels may be formed to extend into formation zones having a higher reservoir production quality, which may be defined as a function of one or more of porosity, permeability, and hydrocarbon saturation. The extended perforation tunnels may also or instead be formed to extend into formation zones having properties that optimize fracture creation and/or propagation, such as formation zones having lower horizontal stress. Location of the formation zones into which the extended perforation tunnels are formed may be defined based on considerations related to distribution of pumped flow rate among the extended perforation tunnels. For example, the quantity of stimulated formation zones may be defined based on“limited entry” considerations for a given limit of pumped flow rate, such as when the pumped flow rate is limited by pressure limitations and/or by equipment availability. Location of the formation zones into which the extended perforation tunnels are formed may also or instead be defined based on reservoir quality.

[00109] The method (120) may further comprise selecting or otherwise defining (128) size (e.g, diameter) of entry points (e.g, openings) in a casing through which the extended perforation tunnels may be formed into a formation. Size of the entry point in the casing may be defined based on size (e.g, diameter) of a downhole tool utilized to penetrate the casing prior to forming of the extended perforation tunnels, or based on size (e.g, diameter) of pre-created holes or other entry points into the formation located in the casing, a fracturing sleeve, or other piece of equipment installed along the wellbore and operable to aid in the forming of extended perforation tunnels. The size of the entry point in the casing may be further utilized to define efficiency of flow rate distribution between a plurality of extended perforation tunnels using a limited entry approach, such as based on perforation friction.

[00110] The method (120) may further comprise selecting or otherwise defining (130) maximum pumping flow rate of stimulation fluid ( e.g ., fracturing fluid) into the well during hydraulic fracturing of the well. The maximum pumping flow rate may be defined, for example, using the limited entry approach that is based on quantity of the formation zones that are selected to be stimulated via the extended perforation tunnels and the size of the entry points in the casing for each of the extended perforation tunnels. The maximum pumping flow rate may also be at least partially defined by other entry points, such as previously created holes or perforations, and their effect on fluid distribution between target formation zones. If the well is planned to be fracture stimulated in several stages, a staging program (e.g., strategy, plan) for forming and stimulating such extended perforation tunnels using hydraulic fracturing may be defined, as described below. The maximum pumping flow rate during each fracturing stage may be limited, for example, by capability of pumping equipment and pressure limits of completion equipment, among other considerations.

[00111] The method (120) may further comprise selecting or otherwise defining (132) size (e.g, diameter) of extended perforation tunnels extending from the wellbore through the formation. The size of extended perforation tunnels in each formation zone may be selected or otherwise defined based on one or more criteria, such as friction of the fracturing fluid pumped through the extended perforation tunnels. Methods of defining fluid friction may include, for example, lab studies, computations accounting for fluid rheology, and downhole measurements. Diameter of the extended perforation tunnels may be maintained above a threshold size to maintain efficient fluid delivery into the formation because of the friction related pressure losses caused by a decreased diameter. The diameter of the extended perforation tunnels in each formation zone may be defined based on fracture initiation pressure and locations for fracture initiation. Among other parameters, fracture initiation pressure depends on the size of the casing entry points. Accordingly, fracture initiation pressure and fracture initiation locations may be controlled by enlarging diameter of the extended perforation tunnels at locations where fractures are planned to be created.

[00112] The method (120) may further comprise selecting or otherwise defining (134) candidate well completion programs, wherein each candidate well completion program differs with respect to at least one well completion parameter. The well completion parameters may be or comprise extended perforation tunnel parameters related to characteristics or features of the extended perforation tunnels. For example, a well completion parameter may include the quantity ( i.e ., number) of the extended perforation tunnels extending into or through at least one candidate formation zone. Another well completion parameter may include shape or geometry ( e.g ., size, length, profile, orientational geometry, contour etc.) of the extended perforation tunnels extending into the formation and/or of the entry points (e.g., openings) in a casing through which the extended perforation tunnels are formed into the formation. Contour of an extended perforation tunnel may be or comprise change in the cross-sectional shape and/or the size of the cross-sectional shape of the extended perforation tunnel with respect to the length of the extended perforation tunnel. Orientational geometry of an extended perforation tunnel may be or comprise change in the orientation of the extended perforation tunnel with respect to the length of the extended perforation tunnel. The shape or geometry (e.g, size, diameter) of extended perforation tunnels and/or of the entry points may be selected or otherwise defined based on one or more criteria described above. Still another well completion parameter may include orientation angle of the extended perforation tunnels extending into or through at least one candidate formation zone. Orientation of the extended perforation tunnels in a formation zone may be defined based on simplicity of fracture initiation and propagation. For example, orientation of the extended perforation tunnels in a formation zone may be selected along a direction that maximizes or minimizes likelihood of fracture initiation. In the case of limited pumping capacity or limited pumped flow rate, fractures may be created just in formation zones completed with extended perforation tunnels, and the extended perforation tunnels in other formation zones may not be stimulated and may be utilized during production to drain a portion of the reservoir that was not penetrated by the fractures. Orientation of the extended perforation tunnels in a formation zone may also be defined based on expected fracture geometry.

[00113] Other well completion parameters may be or comprise hydraulic fracturing treatment parameters. For example, a well completion parameter may include quantity (i.e., number) of hydraulic fracturing stages, wherein each stage is operable to stimulate selected one or more of the candidate formation zones. The quantity of fracturing stages may be defined based on quantity of defined candidate formation zones for placement of extended perforation tunnels and maximum pumping flow rate of stimulation fluid into the well during hydraulic fracturing of the well. The quantity of fracturing stages may be defined based on the limited entry approach, which may be utilized to define the quantity of extended perforation tunnels that can be effectively fracture stimulated with proper or otherwise intended fluid distribution between the formation zones during each fracturing stage based on the pumping flow rate limits. However, one or more of the extended perforation tunnels may not be stimulated, such as because of predesigned orientation and/or geometry of the extended perforation tunnels.

[00114] Other hydraulic fracturing treatment parameters may define or relate to a hydraulic fracturing treatment plan for at least one fracturing stage, including defining pumping flow rate of stimulation fluid into the well during hydraulic fracturing of the well. Such pumping flow rate may be defined based on maximum pumping flow rate, pumping equipment availability for each fracturing stage, and completion equipment limitations for each stage. For example, in certain circumstances, each fracturing stage except the last one may be performed by pumping a fracturing fluid down a fracturing string with a packer and fracturing plugs for isolating stimulated fracturing zones. The last fracturing zone may be fracture stimulated by pumping the fracturing fluid down the casing after isolating a previous fracturing zone with a fracturing plug. Under such circumstances, maximum pumping flow rate during the last fracturing stage may be higher than during each previous fracturing stage. Other well completion parameters may include proppant type and fracturing fluid type. Still other well completion parameters may include fracturing treatment pumping schedule, proppant volumes, and fracturing fluid volumes for each fracturing stage. The pumping schedule and volumes for fracturing treatment for each fracturing stage may be defined based on fracture geometry modeling, such as PKN, P3D, KGD, 3D-coupled fracture propagation models, or other models that may account for fluid dynamics and proppant settling. The pumping schedule may also include fracture geometry modeling that accounts for complexity of fracture network, such as wiremesh or models utilizing Discrete Fracture Network concept. The pumping schedule may also be defined based on aspects of logistics and economics.

[00115] Other well completion parameters may include parameters related to formation zones ( e.g ., pay zones) targeted for stimulation into or through which the extended perforation tunnels may be formed. Such well completion parameters may include properties or characteristics (e.g., geomechanical logs, petrophysical logs) of the target formation zones, including other formation properties or characteristics described above. The target formation zones may be selected from a list of the defined candidate formation zones. For example, stimulation operations may be initiated with respect to selected target formation zones from a list of defined candidate formation zones for creation of extended perforation tunnels. Selected candidate formation zones may be stimulated, for example, based on economic considerations and efficiency considerations, such as when stimulating too many formation zones utilizes excessive amount of time. Another consideration may include depths ( e.g ., true vertical depth (TVD), measured depth (MD)) of candidate target formation zones where the extended perforation tunnels are planned to be formed. The extended perforation tunnels may be formed just in candidate target formation zones. The extended perforation tunnels may also or instead be formed in selected candidate formation zones that are not defined as target formation zones. Such extended perforation tunnels may be predesigned to avoid stimulation during fracturing treatment, such as via orientation or geometry of the extended perforation tunnels.

[00116] Still other well completion parameters may include considerations related to a staging program, which may include formulating plan for which formation zones are to be stimulated during each fracturing stage and determining a methodology for transitioning from one fracturing stage to another. The staging program may be defined based on selected well completion methodologies. For example, each extended perforation tunnel may be formed before performing hydraulic fracturing. Thereafter, the fracturing may be performed either in one fracturing stage or several fracturing stages. Fluid distribution between several extended perforation tunnels during each fracturing stage may be permitted by utilizing the limited entry approach or by utilizing fracture diverters. Each fracture stimulated formation zone may be isolated from other fracturing zones, for example, by utilizing one or more of fracturing plugs, packers (e.g., including tubing and completion conveyed packers), fracturing sleeves, and fracturing ports. Creation of the extended perforation tunnels and the hydraulic fracturing of the formation zones may be performed sequentially, such as when the extended perforation tunnels are created in one or several formation zones followed by hydraulic fracturing of the formation zones. Such process may be repeated for another formation zone or a subsequent set of formation zones. Zonal isolation between fracturing stages may also be performed.

[00117] The method (120) may further comprise forecasting (136) the results of two or more of the candidate well completion programs based on or otherwise with respect to the defined criteria for evaluating the candidate well completion programs. The forecasting (136) may include modeling or otherwise applying each of the defined candidate well completion programs for at least one of the defined candidate well completion program evaluation criteria. The forecasting (136) may be performed using well behavior modeling during post-fracturing period to generate expected well operating parameters, such as bottom hole flow, bottom hole pressure, production rate, cumulative volumetric production, and expected properties of producing fluid, among other examples. Production forecasting may be performed at least partially based on properties of the formation and designed fracture system.

[00118] The method (120) may also comprise selecting or otherwise defining (138) an optimal candidate well completion program from the forecasted results by comparing or otherwise evaluating the forecasted results based on the defined criteria for evaluating the candidate well completion programs. The defining (138) may include comparing or otherwise evaluating at least two of the forecasted results based on or otherwise with respect to the defined evaluation criteria. The optimal well completion program may be defined based on valuation of forecasted results of each candidate well completion program against the defined evaluation criteria. For example, an optimal well completion program may be defined using cumulative production forecast, as described below. Optimal well completion program may depend on number of parameters and may be substantially different for various types of reservoirs.

[00119] For illustrative purposes, several candidate well completion programs were defined (134) and hydrocarbon production forecasting (136) was performed for each defined candidate well completion program, such as may permit an optimal candidate well completion program to be defined (138). The well completion parameters that changed or varied between the defined candidate well completion programs included whether extended perforation tunnels were present and orientation of the extended perforation tunnels. Some candidate well completion programs included extended perforation tunnels extending along (z.e., aligned with) a direction of fracture propagation, some candidate well completion programs included extended perforation tunnels extending along a direction perpendicular to fracture propagation, and some candidate well completion programs did not include extended perforation tunnels. Table 1 set forth below lists the well completion parameters related to the extended perforation tunnels, including extended perforation tunnel characteristics and depth ( e.g ., true vertical depth (TVD), measured depth (MD)) at which well casing perforations and/or extended perforation tunnels were formed.

Table 1

[00120] Other well completion parameters that changed or varied between the candidate well completion programs included formation oil saturation and formation permeability.

Accordingly, forecasting (136) was performed for two formation models, each having a different formation oil saturation and permeability. Table 2 set forth below lists formation model characteristics and Table 3 set forth below lists fracture treatment design steps utilized for each formation model listed in Table 2. The first formation model was assumed to comprise a constant oil saturation of 0.5 across the reservoir and a homogeneous permeability of 0.10 millidarcys (md). The second formation model was assumed to comprise a variable oil saturation, including a 0.5 saturation in the pay zone and a 0.1 saturation outside of the pay zone. The second formation model was also assumed to comprise a heterogeneous permeability of 10.00 md. No fracture growth restriction was considered.

Table 2

Table 3

[00121] FIGS. 36-38 are forecasted {i.e., modeled) representations of expected geometries of formation fractures formed during fracturing operations based on the well completion parameters listed in Table 1. FIG. 36 shows a vertical wellbore 600 extending through a pay zone 602 of a subterranean formation 604. The wellbore 600 does not have extended perforation tunnels extending therefrom. A formation fracture 606 is shown propagating longitudinally along the wellbore 600 and vertically and horizontally through the formation 604 along a plane of maximum horizontal formation stress (i.e., along a direction of fracture propagation). The fracture 606 is shown having a height 608 that substantially exceeds a height 610 of the formation pay zone 602, extending above and below the pay zone 602. FIG. 37 shows a vertical wellbore 620 extending through a pay zone 622 of a subterranean formation 624. The wellbore 620 has extended perforation tunnels 626 extending therefrom in a direction along a plane of maximum horizontal formation stress. A formation fracture 628 is shown propagating along the plane of maximum horizontal formation stress and longitudinally along the extended perforation tunnels 626. The fracture 628 is shown located within the pay zone 622, wherein the fracture 628 has a height 630 that is substantially equal to or less than a height 632 of the pay zone 622. FIG. 38 shows a vertical wellbore 640 extending through a pay zone 642 of a subterranean formation 644. The wellbore 640 has extended perforation tunnels 646 (one extended perforation tunnel 646 is obstructed from view) extending therefrom in a direction that is transverse (i.e., perpendicular) to a plane of maximum horizontal formation stress. Formation fractures 648 are shown propagating in a direction along and parallel to the plane of maximum horizontal formation stress and transverse with respect to the extended perforation tunnels 646. The fractures are shown having a height 650 that slightly exceeds a height 652 of the formation pay zone 642, extending above and below the pay zone 642.

[00122] FIGS. 39-42 are graphs showing forecasted (i.e., modeled) results for defined candidate well completion programs based on or otherwise with respect to an evaluation criteria of forecasted cumulative oil production, indicated along vertical axes, shown with respect to time, indicated along horizontal axes. The graphs show the forecasted cumulative well productivity depends on well completion parameters, such as extended perforation tunnel parameters ( e.g ., presence of extended perforation tunnels, direction of extended perforation tunnels) listed in Table 1 causing different fracture geometries shown in FIGS. 36-38. The forecasted cumulative well productivity also depends on other well completion parameters, such as candidate formation zone types (e.g., depth, properties) into or through which the extended perforation tunnels may be formed, including the formation types listed in Tables 2 and 3. The graphs further show that the highest producing completion (e.g, no extended perforation tunnels, longitudinal fracture, transverse fractures) changes for each forecast. The cumulative well productivity associated with a single fracture initiated and propagated from a wellbore without extended perforation tunnels is indicated by profiles 662, the cumulative well productivity associated with a fracture extending longitudinally along extended perforation tunnels is indicated by profiles 664, and the cumulative well productivity associated with fractures extending transversely with respect to extended perforation tunnels is indicated by profiles 666.

[00123] FIG. 39 shows the cumulative oil production profiles 662, 664, 666 for the three fracture geometries described above, each having a fracture height that is located within a formation pay zone that has a permeability of 0.10 md. FIG. 39 further shows that the well completion having fractures extending transversely with respect to the extended perforation tunnels, as indicated by profile 666, yield the highest oil production with respect to time. FIG.

40 shows the cumulative oil production profiles 662, 664, 666 for the three fracture geometries described above, each having a fracture height that is located within the formation pay zone that has a permeability of 10.00 md. FIG. 40 further shows that the well completion having a single fracture initiated and propagated from the wellbore, as indicated by profile 662, yields the highest oil production with respect to time. FIG. 41 shows the cumulative oil production profiles 662, 664, 666 for the three fracture geometries described above, each having a fracture height that exceeds height of the formation pay zone that has a permeability of 0.10 md. FIG. 41 further shows that the well completion having fractures extending transversely with respect to the extended perforation tunnels, as indicated by profile 666, yields the highest oil production with respect to time. FIG. 42 shows the cumulative oil production profiles 662, 664, 666 for the three fracture geometries described above, each having a fracture height that exceeds height of the formation pay zone that has a permeability of 10.00 md. FIG. 42 further shows that that the well completion having a fracture extending longitudinally with respect to the extended perforation tunnel, as indicated by profile 664, yields the highest oil production with respect to time.

[00124] The optimal candidate well completion program may be defined (138) by comparing and/or evaluating the forecasted results shown in FIGS. 39-42 based on the defined well evaluation criteria of cumulative oil production. Such comparison indicates that a single fracture, designated by profile 662 shown in FIG. 40, initiated and propagated from a well and having a height that is located within the formation pay zone that has a permeability of 10.00 md yields the highest cumulative oil production over time and, thus, is the optimal candidate well completion program that may be implemented.

[00125] The method (120) described above and shown in FIG. 35 and/or other operations described herein may be performed and/or implemented by utilizing or otherwise in conjunction with at least a portion of one or more examples of one or more instances of the apparatus shown in one or more of FIGS. 1-42 and/or otherwise within the scope of the present disclosure.

However, the methods and operations described herein may be implemented or performed in conjunction with examples of apparatus other than those depicted in FIGS. 1-42 that are also within the scope of the present disclosure. The methods and operations may be performed manually by one or more human operators, and/or may be performed or caused to be performed by a processing device executing coded instructions according to one or more aspects of the present disclosure. For example, the processing device may receive information from the wellsite operator and automatically generate and transmit output information to be analyzed by the wellsite operator, and/or operate or cause a change in an operational parameter of one or more pieces of the wellsite equipment described herein.

[00126] FIG. 43 is a schematic view of at least a portion of an example implementation of a processing device 700 according to one or more aspects of the present disclosure. The processing device 700 may form at least a portion of one or more electronic devices utilized at the well construction system 10 or located offsite. The following description refers to FIGS. 1- 43, collectively.

[00127] The processing device 700 may be in communication with various sensors, actuators, controllers, and other devices of the well construction system 10. The processing device 700 may be operable to receive coded instructions 732 from human operators and sensor data generated by the sensors, process the coded instructions 732 and the sensor data, and

communicate control data to local controllers and/or the actuators to execute the coded instructions 732 to implement at least a portion of one or more example methods and/or operations described herein, such as the methods (100), (110), and/or to implement at least a portion of one or more of the example systems described herein. The processing device 700 may also or instead be operable to receive the coded instructions 732, such as comprising the information defined via the method steps (122), (124), (126), (128), (130), (132), (134) of the method (120), process such information, and output (136) forecasts or models of the defined candidate well completion programs for analysis or comparison by the human operators. The processing device 700 may also or instead automatically define (138) the optimal candidate well completion program.

[00128] The processing device 700 may be or comprise, for example, one or more processors, special-purpose computing devices, servers, personal computers ( e.g ., desktop, laptop, and/or tablet computers), personal digital assistants, smartphones, internet appliances, and/or other types of computing devices. The processing device 700 may comprise a processor 712, such as a general-purpose programmable processor. The processor 712 may comprise a local memory 714, and may execute coded instructions 732 present in the local memory 714 and/or another memory device. The processor 712 may execute, among other things, the machine-readable coded instructions 732 and/or other instructions and/or programs to implement the example methods and/or operations described herein. The programs stored in the local memory 714 may include program instructions or computer program code that, when executed by the processor 712 of the processing device 700, may cause the well construction system 10 and/or other devices to perform the example methods (100), (110), (120) and/or other operations described herein. The processor 712 may be, comprise, or be implemented by one or more processors of various types suitable to the local application environment, and may include one or more of general-purpose computers, special-purpose computers, microprocessors, digital signal processors (DSPs), field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), and processors based on a multi-core processor architecture, as non-limiting examples. Of course, other processors from other families are also appropriate.

[00129] The processor 712 may be in communication with a main memory 716, such as may include a volatile memory 718 and a non-volatile memory 720, perhaps via a bus 722 and/or other communication means. The volatile memory 718 may be, comprise, or be implemented by random access memory (RAM), static random access memory (SRAM), synchronous dynamic random access memory (SDRAM), dynamic random access memory (DRAM), RAMBUS dynamic random access memory (RDRAM), and/or other types of random access memory devices. The non-volatile memory 720 may be, comprise, or be implemented by read-only memory, flash memory, and/or other types of memory devices. One or more memory controllers (not shown) may control access to the volatile memory 718 and/or non-volatile memory 720.

[00130] The processing device 700 may also comprise an interface circuit 724. The interface circuit 724 may be, comprise, or be implemented by various types of standard interfaces, such as an Ethernet interface, a universal serial bus (USB), a third generation input/output (3GIO) interface, a wireless interface, a cellular interface, and/or a satellite interface, among others. The interface circuit 724 may also comprise a graphics driver card. The interface circuit 724 may also comprise a communication device, such as a modem or network interface card to facilitate exchange of data with external computing devices via a network ( e.g ., Ethernet connection, digital subscriber line (DSL), telephone line, coaxial cable, cellular telephone system, satellite, etc.). One or more of the local controllers, the sensors, and the actuators of the well construction system 10 may be connected with the processing device 700 via the interface circuit 724, such as may facilitate communication between the processing device 700 and the local controllers, the sensors, and/or the actuators.

[00131] One or more input devices 726 may also be connected to the interface circuit 724.

The input devices 726 may permit the human operators to enter the coded instructions 732, such as control commands, processing routines, operational settings and set-points, including the information defined via the method steps (122), (124), (126), (128), (130), (132), (134) of the method (120). The input devices 726 may be, comprise, or be implemented by a keyboard, a mouse, a joystick, a touchscreen, a track-pad, a trackball, an isopoint, and/or a voice recognition system, among other examples. One or more output devices 728 may also be connected to the interface circuit 724. The output devices 728 may be, comprise, or be implemented by video output devices (e.g., an LCD, an LED display, a CRT display, a touchscreen, etc.), printers, and/or speakers, among other examples. The processing device 700 may also communicate with one or more mass storage devices 730 and/or a removable storage medium 734, such as may be or include floppy disk drives, hard drive disks, compact disk (CD) drives, digital versatile disk (DVD) drives, and/or USB and/or other flash drives, among other examples.

[00132] The coded instructions 732 may be stored in the mass storage device 730, the main memory 717, the local memory 714, and/or the removable storage medium 734. Thus, the processing device 700 may be implemented in accordance with hardware (perhaps implemented in one or more chips including an integrated circuit, such as an ASIC), or may be implemented as software or firmware for execution by the processor 712. In the case of firmware or software, the implementation may be provided as a computer program product including a non-transitory, computer-readable medium or storage structure embodying computer program code (i.e., software or firmware) thereon for execution by the processor 712. The coded instructions 732 may include program instructions or computer program code that, when executed by the processor 712, may perform the processes and/or operations associated with the method (120) and/or cause the well construction system 10 to perform the processes and/or operations associated with the methods (100), (110) disclosed herein.

[00133] In view of the entirety of the present disclosure, including the figures and the claims, a person having ordinary skill in the art will readily recognize that the present disclosure introduces a method comprising: defining a plurality of candidate well completion programs for a well, wherein each of the candidate well completion programs includes hydraulic fracturing of the well, wherein each of the candidate well completion programs differs with respect to at least one well completion parameter, and wherein at least one of the candidate well completion programs comprises forming extended perforation tunnels extending into a formation

surrounding the well; defining an evaluation criteria for evaluating the candidate well completion programs; forecasting results of the candidate well completion programs with respect to the defined evaluation criteria; comparing the forecasted results of the candidate well completion programs with respect to the defined evaluation criteria; and defining an optimal one of the candidate well completion programs based on the comparison of the forecasted results.

[00134] The well completion parameters may comprise at least one of: quantity of the extended perforation tunnels; orientation of the extended perforation tunnels with respect to principal stresses of the formation; diameter of the extended perforation tunnels; length of the extended perforation tunnels; orientational geometry of the extended perforation tunnels; and contour of the extended perforation tunnels.

[00135] The extended perforation tunnels may have a length of at least about ten feet (three meters).

[00136] At least one of the candidate well completion programs may comprise forming the extended perforation tunnels extending into the formation such that at least a portion of the extended perforation tunnels extends: along a plane comprising the maximum horizontal stress of the formation; or perpendicularly to the plane comprising the maximum horizontal stress of the formation.

[00137] The well completion parameters may comprise at least one of: staging program type; quantity of fracturing stages; pumping flow rate; pumping schedule; proppant type; proppant volume; fracturing fluid type; and fracturing fluid volume.

[00138] The well completion parameters may be defined using properties of the formation.

[00139] The method may comprise, before defining the plurality of candidate well completion programs for the well, at least one of: defining candidate formations through which the well extends and into which the extended perforation tunnels are formed; defining size of openings in a casing through which the extended perforation tunnels are formed into the formation; defining maximum pumping flow rate of fluid into the well during hydraulic fracturing of the well; and defining diameter of the extended perforation tunnels formed into the formation.

[00140] At least one of the candidate well completion programs may comprise: perforating a casing installed in the well; or opening ports of fracturing sleeves of piping installed in the well.

[00141] At least two of the candidate well completion programs may comprise forming extended perforation tunnels extending into the formation, and at least two of the well completion programs may comprise different orientations of the extended perforation tunnels with respect to principal stresses of the formation. The well completion parameters may further comprise at least one of: quantity of the extended perforation tunnels; diameter of the extended perforation tunnels; length of the extended perforation tunnels; orientational geometry of the extended perforation tunnels; and contour of the extended perforation tunnels. The extended perforation tunnels may have a length of at least ten feet (three meters). The different orientations of the extended perforation tunnels with respect to the formation surrounding the well may comprise the extended perforation tunnels extending: along a plane comprising the maximum horizontal stress of the formation; and perpendicularly to the plane comprising the maximum horizontal stress of the formation. The well completion parameters may further comprise at least one of: staging program type; quantity of fracturing stages; pumping flow rate; pumping schedule; proppant type; proppant volume; fracturing fluid type; and fracturing fluid volume. The well completion parameters may be defined using properties of the formation. The method may further comprise, before defining the plurality of candidate well completion programs for the well, at least one of: defining candidate formations through which the well extends and into which the extended perforation tunnels are formed; defining size of openings in a casing through which the extended perforation tunnels are formed into the formation; defining maximum pumping flow rate of fluid into the well during hydraulic fracturing of the well; and defining diameter of the extended perforation tunnels formed into the formation. At least one of the candidate well completion programs may comprise: perforating a casing installed in the well; or opening ports of fracturing sleeves of piping installed in the well.

[00142] The present disclosure also introduces a method comprising: defining a plurality of candidate well completion programs for a well, wherein each of the candidate well completion programs includes hydraulic fracturing of the well, wherein each of the candidate well completion programs differs with respect to at least one well completion parameter, wherein at least one of the candidate well completion programs comprises forming extended perforation tunnels extending into a formation surrounding the well, and wherein at least one of the well completion parameters is a parameter of one or more of the extended perforation tunnels;

defining an evaluation criteria for evaluating the candidate well completion programs;

forecasting results of the candidate well completion programs with respect to the defined evaluation criteria; comparing the forecasted results of the candidate well completion programs with respect to the defined evaluation criteria; and defining an optimal one of the candidate well completion programs based on the comparison of the forecasted results.

[00143] The well completion parameters may comprise at least one of: quantity of the extended perforation tunnels; orientation of the extended perforation tunnels with respect to principal stresses of the formation; diameter of the extended perforation tunnels; length of the extended perforation tunnels; orientational geometry of the extended perforation tunnels; and contour of the extended perforation tunnels.

[00144] The extended perforation tunnels may have a length of at least ten feet (three meters).

[00145] At least one of the candidate well completion programs may comprise forming the extended perforation tunnels extending into the formation such that at least a portion of the extended perforation tunnels extends: along a plane comprising the maximum horizontal stress of the formation; or perpendicularly to the plane comprising the maximum horizontal stress of the formation.

[00146] The well completion parameters may further relate to parameters of the hydraulic fracturing of the well, and such well completion parameters may comprise at least one of: staging program type; quantity of fracturing stages; pumping flow rate; pumping schedule; proppant type; proppant volume; fracturing fluid type; and fracturing fluid volume.

[00147] The well completion parameters may be defined using properties of the formation.

[00148] The method may further comprise, before defining the plurality of candidate well completion programs for the well, at least one of: defining candidate formations through which the well extends and into which the extended perforation tunnels are formed; defining size of openings in a casing through which the extended perforation tunnels are formed into the formation; defining maximum pumping flow rate of fluid into the well during hydraulic fracturing of the well; and defining diameter of the extended perforation tunnels formed into the formation.

[00149] At least one of the candidate well completion programs may comprise: perforating a casing installed in the well; or opening ports of fracturing sleeves of piping installed in the well.

[00150] 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.

[00151] 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

WHAT IS CLAIMED IS:

1. A method comprising:

defining a plurality of candidate well completion programs for a well, wherein each of the

candidate well completion programs includes hydraulic fracturing of the well, wherein each of the candidate well completion programs differs with respect to at least one well completion parameter, and wherein at least one of the candidate well completion programs comprises forming extended perforation tunnels extending into a formation surrounding the well;

forecasting results of the candidate well completion programs with respect to the defined

evaluation criteria;

comparing the forecasted results of the candidate well completion programs with respect to the defined evaluation criteria; and

defining an optimal one of the candidate well completion programs based on the comparison of the forecasted results.

2. The method of claim 1 wherein the well completion parameters comprise at least one of:

quantity of the extended perforation tunnels;

orientation of the extended perforation tunnels with respect to principal stresses of the formation; diameter of the extended perforation tunnels;

length of the extended perforation tunnels;

orientational geometry of the extended perforation tunnels; and

contour of the extended perforation tunnels.

3. The method of claim 1 wherein the extended perforation tunnels have a length of at least about ten feet (three meters).

4. The method of claim 1 wherein at least one of the candidate well completion programs comprises forming the extended perforation tunnels extending into the formation such that at least a portion of the extended perforation tunnels extends:

along a plane comprising the maximum horizontal stress of the formation; or

perpendicularly to the plane comprising the maximum horizontal stress of the formation.

5. The method of claim 1 wherein the well completion parameters comprise at least one of: staging program type;

quantity of fracturing stages;

pumping flow rate;

pumping schedule;

proppant type;

proppant volume;

fracturing fluid type; and

fracturing fluid volume.

6. The method of claim 1 wherein the well completion parameters are defined using properties of the formation.

7. The method of claim 1 further comprising, before defining the plurality of candidate well completion programs for the well, at least one of:

defining candidate formations through which the well extends and into which the extended

perforation tunnels are formed;

defining size of openings in a casing through which the extended perforation tunnels are formed into the formation;

defining maximum pumping flow rate of fluid into the well during hydraulic fracturing of the well; and

defining diameter of the extended perforation tunnels formed into the formation.

8. The method of claim 1 wherein at least one of the candidate well completion programs comprises:

perforating a casing installed in the well; or

opening ports of fracturing sleeves of piping installed in the well.

9. The method of claim 1 wherein at least two of the candidate well completion programs

comprises forming extended perforation tunnels extending into the formation, and wherein at least two of the well completion programs comprise different orientations of the extended perforation tunnels with respect to principal stresses of the formation.

10. The method of claim 9 wherein the well completion parameters further comprise at least one of:

quantity of the extended perforation tunnels;

diameter of the extended perforation tunnels;

length of the extended perforation tunnels;

orientational geometry of the extended perforation tunnels; and

contour of the extended perforation tunnels.

11. The method of claim 9 wherein the extended perforation tunnels have a length of at least ten feet (three meters).

12. The method of claim 9 wherein the different orientations of the extended perforation tunnels with respect to the formation surrounding the well comprise the extended perforation tunnels extending:

along a plane comprising the maximum horizontal stress of the formation; and

13. The method of claim 9 wherein the well completion parameters further comprise at least one of:

staging program type;

quantity of fracturing stages;

pumping flow rate;

pumping schedule;

proppant type;

proppant volume;

fracturing fluid type; and

fracturing fluid volume.

14. The method of claim 9 wherein the well completion parameters are defined using properties of the formation.

15. The method of claim 9 further comprising, before defining the plurality of candidate well completion programs for the well, at least one of:

defining candidate formations through which the well extends and into which the extended perforation tunnels are formed;

16. The method of claim 9 wherein at least one of the candidate well completion programs comprises:

perforating a casing installed in the well; or

opening ports of fracturing sleeves of piping installed in the well.

17. A method comprising:

candidate well completion programs includes hydraulic fracturing of the well, wherein each of the candidate well completion programs differs with respect to at least one well completion parameter, wherein at least one of the candidate well completion programs comprises forming extended perforation tunnels extending into a formation surrounding the well, and wherein at least one of the well completion parameters is a parameter of one or more of the extended perforation tunnels;

evaluation criteria;

18. The method of claim 17 wherein the well completion parameters comprise at least one of: quantity of the extended perforation tunnels;

length of the extended perforation tunnels;

orientational geometry of the extended perforation tunnels; and

contour of the extended perforation tunnels.

19. The method of claim 17 wherein the extended perforation tunnels have a length of at least ten feet (three meters).

20. The method of claim 17 wherein at least one of the candidate well completion programs comprises forming the extended perforation tunnels extending into the formation such that at least a portion of the extended perforation tunnels extends:

along a plane comprising the maximum horizontal stress of the formation; or

21. The method of claim 17 wherein the well completion parameters further relate to parameters of the hydraulic fracturing of the well, and wherein such well completion parameters comprise at least one of:

staging program type;

quantity of fracturing stages;

pumping flow rate;

pumping schedule;

proppant type;

proppant volume;

fracturing fluid type; and

fracturing fluid volume.

22. The method of claim 17 wherein the well completion parameters are defined using properties of the formation.

23. The method of claim 17 further comprising, before defining the plurality of candidate well completion programs for the well, at least one of:

perforation tunnels are formed;

24. The method of claim 17 wherein at least one of the candidate well completion programs comprises:

perforating a casing installed in the well; or

opening ports of fracturing sleeves of piping installed in the well.