CROSS-REFERENCES TO RELATED APPLICATIONS

[0001] This application claims priority to and the benefit of U.S. Provisional Application No. 62/684,272, entitled“Measurement While Forming Extended Perforation Tunnels,” filed June 13, 2018, and claims priority to and the benefit of U.S. Provisional Application No. 62/684,304, entitled“Formation and Well Evaluation,” filed June 13, 2018, both of which are hereby incorporated by reference in their entireties for all purposes.

BACKGROUND

[0002] The present disclosure generally relates to systems and methods for performing an operation within a borehole in a formation that may contain hydrocarbon fluids and, more particularly, to systems and methods for measuring parameters characterizing an extended perforation tunnel extending from the borehole.

[0003] This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present techniques, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure. Accordingly, it should be understood that these statements are to be read in this light, and not as an admission of any kind.

[0004] Wellbores are drilled through subterranean formations for the extraction of hydrocarbons. Hydraulic fracturing 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 fracturing fluid may include hydrochloric acid and/or other chemicals intended to etch the fracture faces to improve the flow capacity of the fractures. It should be noted that, in certain embodiments, other types of fracture treatments may be utilized including, but not limited to, acid fracturing, slick water fracturing, foam fracturing, proppant-free fracturing, water or steam injection, and others.

[0005] 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.

[0006] Knowing formation properties is relatively important for planning and executing various reservoir development programs. For example, this information may be used to define various aspects of such programs, including number and types of wells, target depths, stimulation programs, types of artificial lift systems, and/or other program aspects. Information about formation properties may come from various sources including, but not limited to, core analysis, formation logging, mud logging, correlations, and others. Formation logging is widely used and is based on acquisition and interpretation of various types of physical (and chemical) measurements taken downhole in wellbores penetrating various formation zones.

[0007] Certain logging tools, including sonic, neutron, gamma ray resistivity tools, and others, are capable of measuring physical properties of rock at relatively short distances from the wellbore, typically limited to several inches or, in the case of sonic tools, to several feet. For formation characterization purposes, logging may be performed on several vertical holes, and then the data acquired may be extrapolated for the formation area around these wells, with appropriate accounting for reservoir stratigraphy. This methodology works well for homogeneous formations. However, it does not provide satisfactory results for heterogeneous formations, formations with unidentified structure, and formations with significant change in reservoir properties within the same formation horizon across a considered area.

SUMMARY

[0008] A summary of certain embodiments described herein is set forth below. It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure.

[0009] Certain embodiments of the present disclosure include a method for formation evaluation that includes creating an extended perforation tunnel from a borehole proximate a stimulation zone so as to extend at least partially into the stimulation zone. The method also includes deploying a downhole evaluation tool into the extended perforation tunnel. The method further includes operating the downhole evaluation tool to acquire data characterizing at least one of a physical property and a chemical property.

[0010] In addition, certain embodiments of the present disclosure include a system that includes a bottom hole assembly configured to be deployed within a borehole positioned in a formation. The bottom hole assembly includes a radial drilling tool configured to create an extended perforation tunnel extending from the borehole. The bottom hole assembly also includes a downhole evaluation tool configured to acquire data characterizing at least one of a physical property and a chemical property

[0011] Various refinements of the features noted above may be undertaken in relation to various aspects of the present disclosure. Further features may also be incorporated in these various aspects as well. These refinements and additional features may exist individually or in any combination. For instance, various features discussed below in relation to one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination. The brief summary presented above is intended to familiarize the reader with certain aspects and contexts of embodiments of the present disclosure without limitation to the claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

[0012] Various aspects of this disclosure may be better understood upon reading the following detailed description and upon reference to the drawings, in which: [0013] FIG. l is a schematic illustration of a well system extending into a subterranean formation, in accordance with embodiments of the present disclosure;

[0014] FIG. 2 is a diagrammatic illustration showing an example of alpha and beta angles at which a given extended perforation tunnel may extend from a borehole, in accordance with embodiments of the present disclosure;

[0015] FIG. 3 is a schematic illustration of a well system having a plurality of extended perforation tunnels extending from a borehole to deliver stimulating fluid, in accordance with embodiments of the present disclosure;

[0016] FIG. 4 is a schematic sectional view of at least a portion of a radial drilling tool system, in accordance with embodiments of the present disclosure;

[0017] FIG. 5 is a schematic view of the radial drilling tool system illustrated in FIG. 4 in a different stage of operation, in accordance with embodiments of the present disclosure;

[0018] FIG. 6 is a schematic view of the radial drilling tool system illustrated in FIGS. 4 and 5 in a different stage of operation, in accordance with embodiments of the present disclosure;

[0019] FIG. 7 is a schematic sectional view of at least a portion of another example radial drilling tool system, in accordance with embodiments of the present disclosure;

[0020] FIG. 8 is a three-dimensional element of a subterranean formation having X-Y-Z coordinates and being subjected to local stresses, in accordance with embodiments of the present disclosure; [0021] FIG. 9 is a schematic view of at least a portion of an example wellbore system that includes a plurality of extended perforation tunnels, in accordance with embodiments of the present disclosure;

[0022] FIGS. 10 and 11 are schematic views illustrating a downhole evaluation tool system positioned in an extended perforation tunnel to acquire information characterizing a desired property or properties, in accordance with embodiments of the present disclosure;

[0023] FIGS. 12 and 13 are schematic views illustrating how real-time downhole measurements during creation of an extended perforation tunnel may aid the process of creation of the extended perforation tunnel, in accordance with embodiments of the present disclosure; and

[0024] FIG. 14 is a block diagram of at least a portion of a processing device configured to execute instructions to implement the techniques described herein.

PET ATT, ED DESCRIPTION

[0025] One or more specific embodiments of the present disclosure will be described below These described embodiments are only examples of the presently disclosed techniques.

Additionally, in an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers’ specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

[0026] When introducing elements of various embodiments of the present disclosure, the articles“a,”“an,” and“the” are intended to mean that there are one or more of the elements.

The terms“comprising,”“including,” and“having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Additionally, it should be understood that references to“one embodiment” or“an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features.

[0027] As used herein, the terms“connect,”“connection,”“connected,”“in connection with,” and“connecting” are used to mean“in direct connection with” or“in connection with via one or more elements”; and the term“set” is used to mean“one element” or“more than one element.” Further, the terms“couple,”“coupling,”“coupled,”“coupled together,” and “coupled with” are used to mean“directly coupled together” or“coupled together via one or more elements.” As used herein, the terms“up” and“down,”“uphole” and“downhole”, “upper” and“lower,”“top” and“bottom,” and other like terms indicating relative positions to a given point or element are utilized to more clearly describe some elements. Commonly, these terms relate to a reference point as the surface from which drilling operations are initiated as being the top (e.g., uphole or upper) point and the total depth along the drilling axis being the lowest (e.g., downhole or lower) point, whether the well (e.g., wellbore, borehole) is vertical, horizontal or slanted relative to the surface.

[0028] 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.

[0029] 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.

[0030] 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.

[0031] 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.

[0032] As described in greater detail herein, the diameter of the extended perforation tunnels may vary according to the formation and/or other parameters of a given operation. By way of example, the extended perforation tunnels are generally smaller in diameter than a casing used along the borehole from which they extend. However, certain embodiments may utilize extended perforation tunnels equal to or larger in diameter than the borehole. The diameter of the extended perforation tunnels may be selected according to parameters of the formation and/or types of equipment used for creating the extended perforation tunnels. In addition, the resultant diameter of the extended perforation tunnels may vary depending on the particular technique used to create the extended perforation tunnels (e.g., jetting, drilling, or other suitable technique).

[0033] In certain embodiments, the borehole may be drilled at least in part in a non productive zone of the subterranean formation. The non-productive zone may be a zone that contains limited amounts of hydrocarbon fluid or is less desirable with respect to production of hydrocarbon fluid. Depending on the characteristics of the subterranean region, the borehole may be drilled in non-productive rock and/or in a region with petrophysical and geo-mechanical properties different from the properties of the target zone. For example, the borehole may be drilled in a region of the formation having a substantially higher minimum in situ stress relative to that of the target zone. It should be noted that the extended perforation tunnels may be used in many types of formations (e.g., laminated formations) to facilitate flow of fluid to the extended perforation tunnels through fracture networks even in the presence of pinch points between formation layers.

[0034] To facilitate production, at least one extended perforation tunnel may be created, which intersects the borehole and extends into a target zone (e.g., a productive zone containing hydrocarbon fluid). Often, a plurality of extended perforation tunnels may be created to extend from the borehole outwardly into the target zone to serve as extended treatment passages. The target zone may be a single region or separate distinct regions of the formation. In certain embodiments, the borehole may be entirely outside of the target zone, and a plurality of extended perforation tunnels may be created in desired directions to reach the target zone. For example, in certain embodiments, the extended perforation tunnels may be created generally horizontally, generally vertically, generally along desired angles between horizontal and vertical, in generally opposed directions with respect to each other, or at other orientations with respect to each other. In other embodiments, however, the borehole may extend into or through the target zone.

[0035] As described in greater detail herein, the well stimulation may include hydraulic fracturing of the stimulation zone or zones. During hydraulic fracturing, a fracturing fluid may be pumped down through the borehole and out through the plurality of extended perforation tunnels. In general, the fracturing fluid is forced under pressure from the extended perforation tunnels out into the surrounding subterranean formation (e.g., into the surrounding hydrocarbon bearing target zone) to fracture the surrounding subterranean formation. For example, the surrounding subterranean formation may be fractured at a plurality of stimulation zones within the overall target zone.

[0036] It should be noted that, in certain embodiments, the fracturing fluid also may comprise propping agent for providing fracture conductivity after fracture closure. In certain embodiments, the fracturing fluid may comprise acid such as hydrochloric acid, acetic acid, citric acid, hydrofluoric acid, other acids, or mixtures thereof. The fracturing of the stimulation zones within the target zone enhances production of hydrocarbon fluid from the target zone to the wellbore and ultimately to the surface. The target zone may be a productive zone of the subterranean region containing desired hydrocarbon fluid (e.g., oil and/or gas).

[0037] The embodiments described herein provide systems and methods for performing an operation within a borehole in a formation. For example, in certain embodiments, the method includes creating at least one extended perforation tunnel from the borehole. In addition, in certain embodiments, a downhole evaluation tool (e.g., logging tool, sampling tool, sensor, and so forth) may be deployed into the extended perforation tunnel and operated to acquire information characterizing a desired property (e.g., a physical property, a chemical property, or both a physical and chemical property). The embodiments described herein also provide systems and methods for creating extended perforation tunnels while collecting data relating to one or more parameters associated with the extended perforation tunnels. [0038] Turning now to the drawings, FIG. 1 is a schematic illustration of a well system 10 extending into a subterranean formation 12. The well system 10 enables a methodology for enhancing recovery of hydrocarbon fluid (e.g., oil and/or gas) from a well. In certain embodiments, a borehole 14 (e.g., a generally vertical wellbore) is drilled down into the subterranean formation 12. In certain embodiments, the borehole 14 may be drilled into or may be drilled outside of a target zone 16 (or target zones 16) containing, for example, a hydrocarbon fluid 18.

[0039] In the illustrated embodiment, the borehole 14 is a generally vertical wellbore extending downwardly from a surface 20. However, certain operations may create deviations in the borehole 14 (e.g., a lateral section of the borehole 14) to facilitate hydrocarbon recovery. In certain embodiments, the borehole 14 may be created in non-productive rock of the formation 12 and/or in a zone with petrophysical and/or geomechanical properties different from the properties found in the target zone or zones 16.

[0040] At least one extended perforation tunnel 22 (e.g., a plurality of extended perforation tunnels 22, in certain embodiments) may be created to intersect the borehole 14. In the illustrated embodiment, at least two extended perforation tunnels 22 are created to intersect the borehole 14 and to extend outwardly from the borehole 14. For example, in certain

embodiments, the extended perforation tunnels 22 may be created and oriented laterally (e.g., generally horizontally) with respect to the borehole 14. Additionally, in certain embodiments, the extended perforation tunnels 22 may be oriented to extend from the borehole 14 in different directions (e.g., opposite directions) so as to extend into the desired target zone or zones 16. [0041] With reference to FIG. 2, the extended perforation tunnel 22 is not aligned with the orientation of the borehole 14, but is created at some angle relative to the borehole 14 that is characterized by deviation from the direction of the borehole 14 (e.g., angle alpha: 0-90°) and the azimuthal tangential angle (beta 0-90°). For example, the extended perforation tunnels 22 may be oriented at desired alpha angles (e.g., deviation from the direction of the borehole 14) and beta angles (e.g., the azimuthal tangential angle) as illustrated in FIG. 2. The alpha and beta angles may range between 0° and 90° (e.g., from 45° to 90°, in certain embodiments). For example, the extended perforation tunnels 22 may be oriented from 45° to 90° relative to the direction of the borehole 14. In certain embodiments, the extended perforation tunnels 22 may be created and oriented at the alpha angle equal or close to 90° and the beta angle equal or close to 0° with respect to the borehole 14. Additionally, in certain embodiments, the extended perforation tunnels 22 may be oriented to extend from the borehole 14 in different directions (e.g., opposite directions) so as to extend into the desired zone 16. As described in greater detail herein, during a stimulation operation (e.g., a hydraulic fracturing operation), fractures are created, which extend from the extended perforation tunnels 22.

[0042] Returning now to FIG. 1, in general, the extended perforation tunnels 22 provide fluid communication with an interior of the borehole/wellbore 14 to facilitate flow of the desired hydrocarbon fluid 18 from the extended perforation tunnels 22, into borehole 14, and up through borehole 14 to, for example, a collection location at surface 20. Furthermore, in certain embodiments, the extended perforation tunnels 22 may be oriented in selected directions based on the material forming the subterranean formation 12 and/or on the location of desired target zones 16. [0043] Depending on the characteristics of the subterranean formation 12 and the target zones 16, the extended perforation tunnels 22 may be created along various azimuths. For example, in certain embodiments, the extended perforation tunnels 22 may be created in alignment with a direction of maximum horizontal stress, represented by arrow 24, in the formation 12. However, in other embodiments, the extended perforation tunnels 22 may be created along other azimuths, such as in alignment with a direction of minimum horizontal stress in the formation 12, as represented by arrow 26.

[0044] In certain embodiments, the extended perforation tunnels 22 may be created at a desired angle or angles with respect to principal stresses when selecting azimuthal directions.

For example, in certain embodiments, the extended perforation tunnel (or extended perforation tunnels) 22 may be oriented at a desired angle with respect to the maximum horizontal stress in formation 12. It should be noted that, in certain embodiments, the azimuth and/or deviation of an individual extended perforation tunnel 22 may be constant. However, in other embodiments, the azimuth and/or deviation may vary along the individual extended perforation tunnel 22 to, for example, enable creation of the extended perforation tunnel 22 through a desired zone 16 to facilitate recovery of the hydrocarbon fluids 18.

[0045] Additionally, in certain embodiments, at least one of the extended perforation tunnels 22 may be created and oriented to take advantage of a natural fracture 28 or multiple natural fractures 28, which occur in the formation 12. The natural fracture 28 may be used as a flow conduit that facilitates flow of the hydrocarbon fluid 18 into the extended perforation tunnel (or extended perforation tunnels) 22. Once the hydrocarbon fluid 18 enters the extended perforation tunnels 22, the hydrocarbon fluid 18 is able to readily flow into the wellbore 14 for production to the surface 20 and/or other collection location.

[0046] Depending on the parameters of a given formation 12 and hydrocarbon recovery operation, the diameter and length of the extended perforation tunnels 22 also may vary. The extended perforation tunnels 22 are generally longer than the lengths of perforations created in a conventional perforation operation. In certain embodiments, the extended perforation tunnels 22 extend from the borehole 14 at least 10 feet (3.05 meters) into the formation 12 surrounding the borehole 14. However, other embodiments may utilize extended perforation tunnels 22 that extend from the borehole 14 at least 15 feet (4.6 meters) into the formation 12. Yet other embodiments may utilize extended perforation tunnels 22 that extend from the borehole 14 at least 20 feet (6.1 meters) into the formation 12. Indeed, certain embodiments may utilize extended perforation tunnels 22 substantially longer than 20 feet (6.1 meters). For example, in certain embodiments, some of the extended perforation tunnels 22 may extend from the borehole 14 at least 100 feet (30.5 meters), at least 200 feet (61 meters), between 300 feet (91 meters) and 1,600 feet (488 meters), or even more, into the formation 12.

[0047] In certain embodiments, each extended perforation tunnel 22 also has a diameter generally smaller than the diameter of borehole 14 (e.g., smaller than the diameter of a casing used to line borehole 14). With respect to diameter, in certain embodiments, the tunnel diameter may range, for example, from 0.5 inches (12.7 millimeters) to 5.0 inches (12.7 centimeters). However, in other embodiments, the tunnel diameter may be within a range of 0.5 inches (12.7 millimeters) to 10 inches (25.4 centimeters), within a range of 1 inch (25.4 millimeters) and 5 inches (12.7 centimeters), within a range of 1.5 inches (3.8 centimeters) and 3 inches (7.6 centimeters), and so forth. However, in other embodiments, the extended perforation tunnels 22 may utilize a diameter of 2 inches (5.1 centimeters) or less. However, other embodiments may utilize extended perforation tunnels 22 having a diameter of 1.5 inches (3.8 centimeters) or less. The actual lengths, diameters, and orientations of the extended perforation tunnels 22 may be adjusted according to the parameters of the formation 12, the target zones 16, and/or objectives of the hydrocarbon recovery operation.

[0048] FIG. 3 is a schematic illustration of a well system 10 having a plurality of extended perforation tunnels 22 extending from a borehole 14 to deliver stimulating fluid to stimulation zones 30 that are distributed through the target zone(s) 16. Distributing the stimulating fluid under pressure to the stimulation zones 30 creates fracture networks 32. The fracture networks 32 facilitate flow of fluid into the corresponding extended perforation tunnels 22. By way of example, the stimulation operation may include hydraulic fracturing performed to fracture the subterranean formation 12 (e.g., oil- or gas-bearing target zone 16) so as to facilitate flow of the desired fluid along the resulting fracture networks 32 and into the corresponding extended perforation tunnels 22.

[0049] If the stimulation operation is a hydraulic fracturing operation, fracturing fluid may be pumped from the surface 20 under pressure, down through wellbore 14, into the extended perforation tunnels 22, and then into the stimulation zones 30 surrounding the corresponding extended perforation tunnels 22, as indicated by arrows 34. The pressurized fracturing fluid 34 causes the formation 12 to fracture in a manner that creates the fracture networks 32 in the stimulation zones 30. In certain embodiments, the extended perforation tunnels 22/stimulation zones 30 may be fractured sequentially. For example, the fracturing operation may be performed through sequential extended perforation tunnels 22 and/or sequentially through individual extended perforation tunnels 22 to cause sequential fracturing of the stimulation zones 30 and creation of the resultant fracture networks 32.

[0050] As described in greater detail herein, the extended perforation tunnels 22 may be created via a variety of techniques, such as various jetting techniques or drilling techniques. For example, in certain embodiments, drilling equipment may be deployed down into wellbore 14 and used to create the desired number of extended perforation tunnels 22 in appropriate orientations for a given subterranean environment and production operation. However, in other embodiments, the extended perforation tunnels 22 may be created by other suitable techniques, such as jetting techniques, laser techniques, injection of reactive fluid techniques, electrical decomposition techniques, or other tunnel creation techniques. In a specific example, the extended perforation tunnels 22 may be jetted using hydraulic jetting technology similar to hydraulic jetting technologies available from Radial Drilling Services Ltd, Viper Drill of

Houston, Texas, Jett-Drill Well Services Ltd, or Fishbones AS of Stavanger, Norway.

[0051] As described in greater detail herein, the use of extended perforation tunnels 22 during the stimulation operation enables creation of the fracture networks 32 and/or control of the geometries thereof. In general, the fracture networks 32 provide fractures with an increased density, thus increasing the size of the contact area with respect to each target zone 16 containing the hydrocarbon fluid 18. This, in turn, leads to an increase in well productivity as compared to wells completed without utilizing extended perforation tunnels 22.

[0052] FIGS. 4-6 are schematic sectional views of a portion of an example downhole radial drilling tool system positioned within a wellbore 14 and operable to from extended perforation tunnels 22 extending from the wellbore 14. For example, FIG. 4 illustrates a portion of a wellbore 14 including a casing 36 (which may be secured by cement 38 or installed open-hole) extending through a subterranean formation 12. In certain embodiments, a drill string 40 extending through the wellbore 14 includes a deflecting tool 42 operable to deflect or otherwise direct a drilling, cutting, or other boring device toward a sidewall of the wellbore 14 to create an extended perforation tunnel 22. In certain embodiments, the deflecting tool 42 may be rotatably oriented with respect to the wellbore 14, as indicated by arrow 44, to rotatably align or orient an outlet port 46 of the deflecting tool 42 in an intended direction (e.g., a substantially vertical direction). In certain embodiments, an axis 48 of the outlet port 46 is oriented substantially orthogonal (e.g., within 5 degrees, within 2 degrees, within 1 degree, or even closer, to exactly orthogonal) to the casing 36 through which the extended perforation tunnel 22 extends.

[0053] As illustrated in FIG. 5, in certain embodiments, after the deflecting tool 42 is positioned at an intended longitudinal (e.g., axial) location within the wellbore 14 and at an intended rotational orientation, a drilling tool 50 (e.g., a flexible casing drilling string, in certain embodiments) terminating with a drilling, milling, cutting, or other bit 52 may be deployed through the drill string 40, such as via a micro-coil or coiled tubing, to create a perforation 54 (i.e., a hole) through the casing 36. As illustrated in FIG. 6, in certain embodiments, once the perforation 54 is created, the drilling tool 50 may be retracted from the deflecting tool 42 to the surface 20 and a hydraulic jetting tool 56 (i.e., a radial jet cutting tool, in certain embodiments) terminating with a nozzle 58 may be deployed downhole through the drill string 40, such as via a micro-coil or coiled tubing, through the deflection tool 42, and into alignment with or at least partially into the perforation 54. The hydraulic jetting tool 56 may then be operated to discharge a stream 60 of pressurized water or another fluid to create an extended perforation tunnel 22. However, in certain embodiments, instead of utilizing both the drilling tool 50 and the jetting tool 56, a combinatory radial drilling tool (not shown) may be utilized to create both the casing perforation 54 and the extended perforation tunnel 22, such as to minimize or reduce the number of lifting/tripping operations.

[0054] After the extended perforation tunnel 22 is created, the deflecting tool 42 may be reoriented to create another extended perforation tunnel 22 or moved longitudinally along the wellbore 14 to a selected location (e.g., at another formation zone 16). The process may be repeated until the intended number of extended perforation tunnels 22 are created along the entire wellbore 14 or into several formation zones 16.

[0055] Although the deflecting tool 42 is illustrated as being coupled along the drill string 40, in other embodiments, the deflecting tool 42 may be deployed downhole as part of another tool string or otherwise separately from a drill string 40, such as via coiled tubing, and utilized in conjunction with the drilling tool 50 and the jetting tool 56 to create the extended perforation tunnels 22. As described in greater detail herein, stimulation (e.g., fracturing) operations may be performed after the extended perforation tunnels 22 are created. However, fracture or other stimulation treatment operations may be performed in one or more of the formation zones 16 along the wellbore 14 before creating extended perforation tunnels 22 in one or more subsequent formation zones 16.

[0056] It is to be understood that other downhole tools may be utilized to create the extended perforation tunnels 22 within the scope of the present disclosure. For example, FIG. 7 is a schematic sectional view of a portion of a laser cutting tool 62 positioned within a wellbore 14 and operable to create extended perforation tunnels 22 extending from the wellbore 14. In certain embodiments, the laser cutting tool 62 may be conveyed longitudinally along the wellbore 14 (e.g., via coiled tubing 64). After an intended longitudinal position is reached, a portion of the laser cutting tool 62 including a laser emitting port 66 (e.g., optical opening) may be rotated with respect to the wellbore 14, as indicated by arrow 68, to rotatably align or orient the laser emitting port 66 in an intended direction (e.g., a substantially vertical direction). After the intended longitudinal position and rotational orientation are established, the laser cutting tool 62 may be operated to emit a laser beam 70 to create the extended perforation tunnel 22. After the extended perforation tunnel 22 is created, the laser cutting tool 62 may be reoriented to create another extended perforation tunnel 22, or moved longitudinally along the wellbore 14 to a subsequent selected location (e.g., at another formation zone 16), and the process is repeated until the intended number of extended perforation tunnels 22 are created along the entire wellbore 14 or into several formation zones 16.

[0057] Subterranean formations containing the wellbore systems described herein are confined and under stress. FIG. 8 illustrates a three-dimensional element of a subterranean formation 12 having X-Y-Z coordinates and being subjected to local stresses. The element of subterranean formation 12 is also illustrated with a portion of an extended perforation tunnel 22 extending therethrough. As illustrated, the stresses imparted to the element of subterranean formation 12 may be divided into three principal stresses, namely, a vertical stress 72, a minimum horizontal stress 74, and maximum horizontal stress 76. These stresses 72, 74, 76 are normally compressive, anisotropic, and nonhomogeneous, which means that the stresses on the formation 12 are not equal and vary in magnitude on the basis of direction, which controls pressure operable to create 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 76 or along a plane 78 (or another parallel plane) of maximum horizontal formation stress 76 (along a plane 78 perpendicular to the minimum horizontal stress 74). The direction of maximum formation stress 76 may be measured while drilling or otherwise creating 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 wellbore 14 and the extended perforation tunnels 22 for optimal productivity.

[0058] Accordingly, as the hydraulic fractures propagate along the plane 78 of maximum horizontal formation stress 76, extended perforation tunnels 22 may be created extending along (i.e., in alignment with, in a direction of) a plane comprising the maximum horizontal formation stress 76. Such orientation of the extended perforation tunnel 22 may result in a hydraulic fracture originating at the extended perforation tunnel 22 propagating longitudinally along the extended perforation tunnel 22. As illustrated in FIG. 8, because a hydraulically-induced fracture may propagate along the plane of maximum horizontal stress 76, at least a portion of the extended perforation tunnel 22 may be created at an angle 80 with respect to the true vertical 82 such that the extended perforation tunnel 22 extends along (i.e., is aligned with, extends in a direction 84 along) the plane 78 (along the X-Y plane) and not such that the extended perforation tunnel 22 extends through, across, or diagonally to the plane 78 (along the Y-Z plane). Such orientation 84 of the extended perforation tunnel 22 may result in a hydraulic fracture propagating longitudinally along the extended perforation tunnel 22 (e.g., not diagonally across the extended perforation tunnel 22), facilitating longitudinal and, thus, optimal fluid connection between the extended perforation tunnel 22 and the fracture. [0059] 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 22 described herein may substantially improve the efficiency of production, such as by promoting production from a greater number of sedimentary layers in the formation 12. Creating these extended perforation tunnels 22 from one or more wellbores 14 may also facilitate substantial production increase to be achieved. Moreover, the embodiments described herein permit creation of well systems 10 that include a plurality of wellbores 14, each including a corresponding plurality of extended perforation tunnels 22 resulting in production magnification.

[0060] FIG. 9 is a schematic sectional view of at least a portion of an example wellbore system 86 that includes a substantially vertical wellbore portion 88 and a plurality of extended perforation tunnels 22 extending from such substantially vertical wellbore portion 88 through a casing 36 and one or more formation zones 16 of a subterranean formation 12. As illustrated, in certain embodiments, the extended perforation tunnels 22 may extend at selected angles 90, 92 with respect to the substantially vertical wellbore portion 88 and/or a true vertical direction 94 and/or a true horizontal direction 96. For example, assuming that the wellbore system 86 is created in a three-dimensional space X-Y-Z, one or more of the extended perforation tunnels 22 may deviate or otherwise extend from the substantially vertical wellbore portion 88, along the X- Y plane and/or the Y-Z plane, at angles 92 ranging between about -45 degrees and about 45 degrees from the true horizontal 96 (between about 45 degrees and about 135 degrees with respect to the substantially vertical wellbore portion 88 and/or the true vertical 94). However, in other embodiments, angles 92 that are greater than -45 and 45 degrees from the true horizontal 96 are also within the scope of the present disclosure, resulting in extended perforation tunnels 22 that may be substantially vertical or closer to the true vertical 94 than to the true horizontal 96. Furthermore, in other embodiments, one or more of the extended perforation tunnels 22 may also extend from the substantially vertical wellbore portion 88 and/or the true vertical 94 along the X- Z plane at any angle 90 (i.e., between zero and 360 degrees) or in any azimuthal direction 98 around the substantially vertical wellbore portion 88 and/or the true vertical 94. For example, in certain embodiments, the extended perforation tunnels 22 may be created to extend from the substantially vertical wellbore portion 88 in a direction along or aligned with a plane of maximum horizontal formation stress (e.g., along direction 84 and plane 78, as illustrated in FIG. 8), which may result in a hydraulic fracture propagating longitudinally along the extended perforation tunnels 22. However, in other embodiments, the extended perforation tunnels 22 may be created to extend from the substantially vertical wellbore portion 88 in a direction that is transverse (i.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 22.

[0061] The present disclosure is further directed to performing an operation within a borehole 14 in a formation 12 that may contain hydrocarbon fluids 18. In certain embodiments, the method includes creating at least one extended perforation tunnel 22 from the borehole 14 so as to extend at least 10 feet (3.05 meters) from the borehole 14. In certain embodiments, the extended perforation tunnel or extended perforation tunnels 22 may be created with a diameter selected from a range of between 0.5 inches (12.7 millimeters) and 5.0 inches (12.7 centimeters). In certain embodiments, a well stimulation procedure (e.g., a hydraulic fracturing procedure) may be performed through the at least one extended perforation tunnel 22. In addition, as described in greater detail herein, in certain embodiments, a downhole evaluation tool (e.g., logging tool, sampling tool, sensor, and so forth) may be deployed into the at least one extended perforation tunnel 22. In certain embodiments, the downhole evaluation tool may be operated to acquire information characterizing a desired property (e.g., data relating to a physical property and/or a chemical property).

[0062] Depending on the embodiment, the downhole evaluation tool may be deployed into the at least one extended perforation tunnel 22 during creation of the extended perforation tunnel 22 or after creation of the extended perforation tunnel 22. Furthermore, the data on the desired property or properties may be stored on a memory device (e.g., stored downhole for later retrieval) or transmitted to the surface 20 during or after creation of the extended perforation tunnel 22. For example, in certain embodiments, informational data characterizing a desired property measured by the downhole evaluation tool may be transmitted in real time (e.g., as the data is collected by the downhole evaluation tool) to a processing system located at the surface 20.

[0063] In certain embodiments, the downhole evaluation tool may be used in extended perforation tunnels 22 through which fracturing operations have been performed or in extended perforation tunnels 22 that have not been used for fracturing operations. By way of example, in certain embodiments, the downhole evaluation tool may be moved through at least one extended perforation tunnel 22 to collect desired data on various selected properties. In some

applications, the procedure may be used in extended perforation tunnels 22 through which a propped hydraulic fracture treatment has been performed, or through which the fracture treatment will subsequently be performed. In certain embodiments, the technique may be used with a variety of other well stimulation techniques, including acid fracturing, slick water fracturing, matrix stimulation, and proppant free fracturing.

[0064] In certain embodiments, production of well fluid is promoted by providing a borehole 14 positioned proximate a stimulation zone 30. For example, in certain embodiments, the borehole 14 may be a vertical or deviated (e.g., horizontal) borehole 14 positioned along or through the stimulation zone 30. In certain embodiments, at least one extended perforation tunnel 22 may be oriented to extend from the borehole 14 at least partially in the stimulation zone 30. Doing so enables each extended perforation tunnel 22 to be used for facilitating initiation of fractures in the stimulation zone 30 during a stimulation operation. By way of example, the stimulation operation may include pumping fracturing fluid under pressure through the borehole 14 and the at least one extended perforation tunnel 22.

[0065] In certain embodiments, the systems and methods may include completing a well via creation of extended perforation tunnels 22 having lengths of at least 10 feet (3.05 meters) into a stimulation zone 30 of a surrounding formation 12. In some applications, the extended perforation tunnels 22 may extend up to 300 feet (91 meters) or more. In certain embodiments, a stimulation operation in the form of hydraulic fracturing may be performed by pumping hydraulic fracturing fluid into the extended perforation tunnels 22. As described in greater detail herein, in certain embodiments, the extended perforation tunnels 22 may be created using, for example, radial drilling methods (e.g., jetting or drilling) into a formation 12 at a desired angle (e.g., 90° or other suitable angle) relative to the wellbore 14 or other type of borehole. In certain embodiments, the geometry of the extended perforation tunnels 22 in selected zones may be adjusted to facilitate fracture initiation in such zones. [0066] In certain embodiments, the extended perforation tunnel or extended perforation tunnels 22 also may be used to facilitate formation logging, sampling, and/or other downhole evaluation techniques to acquire information about the formation 12 (e.g., information about well fluids, stimulation operation, or other well related properties). By way of example, a logging tool or sampling tool may be deployed into at least one of the extended perforation tunnels 22 either during creation of the extended perforation tunnel 22 or after creation of the extended perforation tunnel 22.

[0067] With the methodology described herein, many traditional problems associated with acquiring information on formation properties may be reduced or eliminated. The current methodology facilitates measuring of formation properties at multiple locations between wells. As described in greater detail herein, the methodology may be enabled through creation and logging of extended perforation tunnels 22, which may penetrate into the formation 12 from a main wellbore 14 to a distance greater than 10 feet (3.05 meters). In certain embodiments, such extended perforation tunnels 22 may have a diameter substantially smaller than the diameter of the main wellbore 14. In certain embodiments, such extended perforation tunnels 22 may be logged using micro-logging tools utilizing the same principles utilized by traditional logging tools. The same extended perforation tunnels 22 also may be used for collecting samples of formation rock and formation fluid from various portions of the reservoir.

[0068] FIG. 10 illustrates a downhole evaluation system 100 that includes a downhole evaluation tool 102 positioned in a bottom hole assembly (BHA) 104 deployed downhole into a selected extended perforation tunnel 22 via a suitable conveyance 106 (e.g., tubing). In certain embodiments, the downhole evaluation tool 102 may include a logging tool, a sampling tool, other types of sensors, or other types of devices configured to help acquire data related to the well. Although illustrated as being used as part of a corresponding BHA 104 during creation of each extended perforation tunnel 22, in other embodiments, the downhole evaluation tool 102 may instead be deployed into an extended perforation tunnel 22 after creation of the extended perforation tunnel 22.

[0069] In certain embodiments, the downhole evaluation tool 102 may be used to collect data while penetrating with the corresponding BHA 104 into the formation 12, or while retrieving the corresponding BHA 104 from the extended perforation tunnel 22. In certain embodiments, when stimulation techniques are employed, the downhole evaluation tool 102 may be used before, during, and/or after performance of the well stimulation to collect desired data related to formation 12. In certain embodiments, a stimulation operation may include a diagnostic fracturing operation. In this case, as well as in the case of performing well stimulation operations, the evaluation tool 102 may be positioned in the extended perforation tunnel 22 outside of the casing 36, and may be used for measuring parameters of the fracturing treatment directly in the stimulated zone 30.

[0070] As such, the downhole evaluation tool 102 may be used to acquire information relating to the formation 12. In certain embodiments, the information/data collected by the downhole evaluation tool 102 may be stored in a downhole memory device 108 for later retrieval and processing at, for example, a surface location. For example, in certain embodiments, the downhole memory device 108 may be positioned in the BHA 104 and configured to

communicate with downhole evaluation tool 102. However, in other embodiments, the downhole memory device 108 may be part of the downhole evaluation tool 102. [0071] Depending on the embodiment, the information/data collected by the downhole evaluation tool 102 may be transmitted to a data processing device 110 (e.g., control system), which may be located at the surface 20 or other suitable location. In certain embodiments, the downhole evaluation tool 102 is configured to communicate with the processing device 110 via wireless communication (e.g., using wireless transmitters, receivers, transceivers, and so forth, in the downhole evaluation tool 102 and the processing device 110) or a suitable wired

communication line 112 to enable real-time data transfer (e.g., while the data is collected) from the downhole evaluation tool 102 to the processing device 110. Examples of real-time transmission techniques via the communication line 112 include data transmission through fiber optic cables, data transmission through electrical cables, data transmission through pressure pulsations, or other suitable real-time data transmission techniques.

[0072] In certain embodiments, data may be collected by the downhole evaluation tool 102 while the downhole evaluation tool 102 remains stationary. However, in other embodiments, the data may be collected while the downhole evaluation tool 102 is moved farther along the corresponding extended perforation tunnel 22, as indicated by arrow 114. In certain embodiments, the data may be collected by the downhole evaluation tool 102 as the downhole evaluation tool 102 is being withdrawn from the corresponding extended perforation tunnel 22 in the direction indicated by arrow 116.

[0073] As illustrated in FIG. 11, certain embodiments may incorporate a tunnel creation tool 118 (e.g., such as the radial drilling tool systems described herein with respect to FIGS. 4-7) into the bottom hole assembly 104. In certain embodiments, the tunnel creation tool 118 may be operated before or during collection of data by the downhole evaluation tool 102. As described in greater detail herein, the tunnel creation tool 118 may be used to create the extended perforation tunnel or extended perforation tunnels 22 with a desired diameter (e.g., between 0.5 inches (12.7 millimeters) and 5.0 inches (12.7 centimeters), in certain embodiments) and a desired length (e.g., at least 10 feet (3.05 meters) and up to 300 feet (91 meters) or more, in certain embodiments). Depending on the type of tunnel creation tool 118 used, the cross- sectional area of the extended perforation tunnel 22 being created may vary from, for example, a generally circular shape to more complex (e.g., non-circular) geometries, such as a generally rectangular shape, a generally triangular shape, a generally polygonal (e.g.. hexagonal, and so forth), or any other relatively complex cross-sectional shapes.

[0074] It will be appreciated that the term“generally” is meant to convey that the actual non circular cross-sectional geometries that are created by the tunnel creation tool 118 are of the particular shape, but with relatively minor variances from that particular shape, which may be expected depending on the particular tunnel creation techniques used (e.g., jetting, drilling, and so forth). As such, for example, when referring to shapes of the non-circular cross-sectional geometries as“generally rectangular”, this is meant to convey that the intended shapes of the non-circular cross-sectional geometries (e.g., using the particular tunnel creation techniques) are rectangular, but that relatively minor variances (e.g., within an inch or so) from being exactly rectangular may be created.

[0075] As described in greater detail herein, in certain embodiments, the tunnel creation tool 118 may include a drilling tool 50 or a jetting tool 56 having jetting nozzles, which may be static or located in a rotary jetting head. The jetting nozzles of the jetting tool 56 may be arranged to create a variety of desired cross-sectional geometries with respect to the extended perforation tunnel 22.

[0076] In certain embodiments, the downhole evaluation tool 102 may include various types of tools depending on the desired information to be collected. By way of example, in certain embodiments, the downhole evaluation tool 102 may include a logging device, which may be run as part of bottom hole assembly 104 with or without a tunnel creation tool 118. In certain embodiments, the logging data collected by the downhole evaluation tool 102 may be transmitted to the surface 20 in real time (e.g., while the logging data is being collected by the downhole evaluation tool 102). Such a logging tool 102 may be used to acquire important information about formation structure and properties of the reservoir in three-dimensional space. The collected information may then be used (e.g., by the processing device 110) for optimizing reservoir development, stimulation treatments, enhancing reservoir productivity, and

development of corresponding operational plans.

[0077] In other embodiments, the downhole evaluation tool 102 may include a sampling tool designed for collecting formation samples and/or fluid samples. After collection, the samples may be carried to the surface 20, and used for further analysis. In certain embodiments, at least some analysis of the collected samples may be performed downhole in, for example, the extended perforation tunnel 22 and/or the borehole 14.

[0078] In certain embodiments, downhole measurements may include measurements of such parameters as pressure, fluid rate (e.g., including multi-phase fluid rate), temperature, fluid density, and so forth, inside or outside of the BHA 104 (and associated radial drilling tool) designed for creation of the extended perforation tunnels 22. In certain embodiments, measurements may be performed at the location of the jetting hose, drilling shaft, or any other moving parts of the BHA 104, for example, with the goal of defining the penetration length of the movable part of the BHA 104 into the formation 12. In certain embodiments, the downhole measurements may include a condition at the BHA 104, a position of the BHA 104, a property of a formation 12, a parameter characterizing fluid surrounding the BHA 104, and so forth.

[0079] In certain embodiments, differential pressure between some of the pressure sensors located at BHA 104 may be measured, such as pressure between the inside and outside of the BHA 104, pressure between the tip of the BHA 104 at the time when the BHA 104 is positioned outside of the casing 36, the pressure inside the wellbore 14, and so forth. For example, in certain embodiments, knowing such pressure differentials may be used (e.g., by the processing device 110) for defining components of near- wellbore friction when injecting into the formation 12 at a certain rate and having the tip of the BHA 104 outside of the casing 36.

[0080] In certain embodiments, the downhole evaluation tool 102 may include various sensing devices (e.g., sensors and probe heads), which may be mounted on the bottom hole assembly 104, for example, and used to effectively penetrate the formation 12 to acquire desired data. Examples of this type of downhole evaluation tool 102 include sensors and probe heads that enable gamma ray measurements, neutron measurements, electromagnetic measurements, resistivity measurements, sonic measurements, acceleration measurements, fluid velocity, fluid turbidity, and/or other desired measurements, which may be analyzed by the processing device 110, for example, for operational purposes, to design stimulation treatments, to optimize production strategies, for formation characterization purposes, and so forth. [0081] In certain embodiments, the downhole evaluation tool 102 also may include combinations of various types of sensors and devices to acquire information characterizing various parameters related to the formation 12, which may facilitate determining how to adjust parameters relating to the creation of the extended perforation tunnels 22, as described in greater detail herein. For example, in certain embodiments, the downhole evaluation tool 102 may include sensors/devices for measuring and collecting directional survey data including orientation, inclination, and azimuth. In certain embodiments, the downhole evaluation tool 102 may also be configured to collect perforation dynamics data including temperatures, shock and vibration data, and rotational speed. The inclination and vibration data may be measured by, for example, three-axis accelerometers of the downhole evaluation tool 102, which may be used to derive drill bit or jetting head movement speed and penetration distance when using the drilling tool 50 or jetting tool 56. In addition, in certain embodiments, the downhole evaluation tool 102 may also be configured to collect tension, load, weight, and other force-related parameters of the downhole evaluation tool 102, which may facilitate determining how to adjust the parameters relating to the creation of the extended perforation tunnels 22, as described in greater detail herein.

[0082] In certain embodiments, the measured and derived data may be sampled and stored in the memory device 108 with timestamps and/or transmitted to the processing device 110 through suitable real-time data transmission techniques. In addition, in certain embodiments, the downhole evaluation tool 102 may be operated statically or dynamically in the corresponding extended perforation tunnel 22 to measure a variety of physical and/or chemical properties including, but not limited to, parameters such as pressure, distance, temperature, fluid flow rate, density, porosity, neutron porosity, neutron density, saturation, hydrocarbon saturation, mineral content, resistivity, sonic velocity or slowness, and intensity of gamma radiation, or various other parameters characterizing the formation 12 or the position of the downhole evaluation tool 102 in the formation 12. In certain embodiments, the parameter or parameters measured by the downhole evaluation tool 102 also may include tension, load, weight, orientation, inclination, azimuth, three-axis acceleration, three-axis rotation speed, jetting head movement speed, jetting head movement distance, drilling head movement speed, and drilling head movement distance.

[0083] As such, the downhole evaluation tool 102 may be constructed and operated to acquire many types of data characterizing individual parameters or combinations of parameters related to formation 12, and to communicate the data relating to the individual parameters of combinations of parameters to the processing device 110 for the purpose of controlling any operations relating to the well, such as the creation and creation of particular geometries of the extended perforation tunnels 22, the delivery of fracturing fluid 34 through the extended perforation tunnels 22, the fracture geometries created by the extended perforation tunnels 22 and the fracturing performed via the extended perforation tunnels 22, and so forth.

[0084] For example, in certain embodiments, the processing device 110 may be configured to adjust one or more tunnel creation parameters that are used during creation of the extended perforation tunnels 22 based at least in part on any of the data acquired by the downhole evaluation tool 102 during creation of the extended perforation tunnels 22. For example, in certain embodiments, the one or more tunnel creation parameters that may be adjusted by the processing device 110 include, but are not limited to, steering orientation for the extended perforation tunnel 22 (i.e., a direction at which the extended perforation tunnel 22 is created), diameter of the extended perforation tunnel 22, fracturing fluid composition (e.g., if the characterization of the formation 12 changes, the type of fracturing fluid may be changed), fracturing fluid pressure, fracturing fluid pumping rate , and running speed of the downhole evaluation tool 102 into the extended perforation tunnel 22. In addition, in certain

embodiments, the processing device 110 may be configured to adjust the one or more tunnel creation parameters that are used during creation of the extended perforation tunnels 22 based at least in part on measurements of equipment positioned at the surface 20.

[0085] As described in greater detail herein, in certain embodiments, any of the downhole measurements described herein may be performed during creation of the extended perforation tunnels 22. The creation of extended perforation tunnels 22, as described herein, takes place in a relatively blind fashion, for example, when the extended perforation tunnels 22 are intended to emerge from a non-vertical main wellbore 14. For example, when an extended perforation tunnel 22 is to be jetted, drilled, or otherwise created, surface-acquired information may be utilized to ascertain characteristics of the extended perforation tunnel 22 using the real-time measurements during creation of the extended perforation tunnel 22, as described herein. When the extended perforation tunnel 22 is created from a vertical section of the well, the amount of force placed on the radial drilling tool (e.g., a drilling tool 50, a jetting tool 56, or other suitable tool) creating the extended perforation tunnel 22, as well as other characteristics of the application, may be directly monitored. However, when the extended perforation tunnel 22 is created from a horizontal section of the well, these types of application characteristics may be less informative about the extended perforation tunnel 22 being created. For example, forces imparted from the surface 20 may be directed at the radial drilling tool. However, they may also be directed at the deployment device, such as coiled tubing at the elbow transition between the vertical and horizontal well sections. Therefore, the force information acquired at the surface 20 may be less informative as it relates to the extended perforation tunnel 22 being created from the horizontal section of the well, after the elbow.

[0086] As such, creation of the extended perforation tunnels 22 as described herein may be complicated by the lack of information about downhole processes, particularly where the extended perforation tunnels 22 are to emerge from a horizontal section of a well. For example, a conclusion about the length of the created extended perforation tunnels 22 may be made based on the length of microcoil fed into the well at the surface 20. At the same time, actual penetration depth into the formation 12 may be different, because it may be impacted by bucking of the jetting/drilling BHA 104 and the microcoil in the wellbore 14. Moreover, no information may be available about the geometry of the created extended perforation tunnel 22 (e.g., straight or deviated, toe up or toe down, and so forth). In another example, when an extended perforation tunnel 22 is created using drilling methodology, with use of a flexible drilling shaft with a drilling bit and a downhole motor, the efficiency of drilling, among other parameters, depends on the weight applied to the drilling shaft and the drill bit. For example, drilling may stop because of stalling of the downhole motor when the weight on the drill bit exceeds a certain limit. Conversely, for a vertical well, such weight may be more or less reliably estimated using surface weight data, whereas this value is typically completely unknown for wells with complex or horizontal geometries. The embodiments described herein are capable of overcoming these problems by performing downhole measurements during creation of an extended perforation tunnel 22, thereby enabling higher operational reliability, minimizing operational costs, and reducing operational risks. [0087] FIGS. 12 and 13 are presented to illustrate the benefits of having downhole measurement data available during creation of the extended perforation tunnels 22 described herein. More specifically, FIG. 12 illustrates the creation of an extended perforation tunnel 22 from a vertical section of a well (e.g. a main bore). Alternatively, FIG. 13 illustrates the creation of an extended perforation tunnel 22 from a horizontal section of the well. In both embodiments, direct downhole measurements have been utilized for enabling creation of the extended perforation tunnel 22 from a well that is cased and cemented using a flexible drilling shaft 40 (e.g., of a drilling tool 50). However, in other embodiments, other types of radial drilling techniques, as described herein, in other types of well sections may benefit from the measurement of downhole parameters and properties during creation of the extended perforation tunnels 22.

[0088] In both embodiments illustrated in FIGS. 12 and 13, the load on the drill bit 52 should ideally be kept within a certain range to enable efficient drilling. For example, applying the load on the bit 52 below the optimal load range may result in an increase in drilling time, and applying the load on the bit 52 above the optimal range may result in the drill bit 52 getting stuck and being unable to continue drilling. In a vertical well, the weight on the drill bit 52 may be primarily defined by the weight of the tubing in the well, and may be computed from the weight of the coiled tubing 64 measured at the gooseneck at the surface 20.

[0089] However, as illustrated in FIG. 13, in the case of a horizontal well section, the weight on the drilling bit 52 is less predictable and controlled by the weight of the coiled tubing 64, as well as by the friction of the coiled tubing 64 in the horizontal section of the well. Without incorporating a real-time downhole evaluation tool 102, for example, above a downhole motor 120 to measure real-time load and torque, the extended perforation tunnel 22 may not be created as successfully. The downhole evaluation tool 102 may, for example, be used for measuring the effective load applied by the coiled tubing 64. In certain embodiments, a signal from the downhole evaluation tool 102 relating to the downhole measurements may be transmitted to the surface 20, for example, using a fiber optic tether or cable deployed in the flow path of the coiled tubing 64, and the processing device 110 may adjust the effective load of the coiled tubing 64 through the control of the weight of the coiled tubing 64 at the gooseneck at the surface 20. In certain embodiments, the downhole measurements may be utilized by the processing device 110 to verify creation of the hole in the casing 36 in advance of creating an extended perforation tunnel 22.

[0090] Because the steps of milling the hole in the casing 36, and creating the extended perforation tunnel 22 may use different types of BHAs 104, and performing time consuming lifting operations in between these steps, it is relatively important to have verification that the hole in the casing 36 is actually created. Conventional techniques lack the ability to perform real-time verification of the creation of a hole in a casing. Rather, conventional techniques are based on extending casing milling time several times in order to ensure the creation of the holes (e.g., a typical time to drill through a casing at a surface may be 15 minutes at a torque of 50 fit- lb, whereas the time of actual milling operation is extended to 1-2 hours in order to ensure that the hole has been created). Specifically, upon completion of the milling operation, the milling BHA is retrieved to the surface and the condition of the mill is inspected to make a decision about whether the hole was created or not. Such a process is relatively subjective and may lead to incorrect conclusions regarding hole creation. In addition, if the conclusion on the creation of the hole in casing is negative, then the whole process is repeated until the indication of the hole creation.

[0091] The embodiments described herein overcome these deficiencies of conventional systems by enabling verification of the hole creation without pulling out the milling BHA 104 to the surface 20. Rather, the verification may be achieved, for example, through deployment of a downhole position sensor on the body of the deflector 42, which may indicate penetration of the drill bit 52 outside of the deflector 42 to the distance required for creation of the hole in the casing 36. In such an embodiment, a signal from the position sensor may be transmitted to the surface 20 using one of the transmission techniques described herein (e.g., including using a fiber optic cable, an electrical cable, pressure pulsations, and so forth) in the tubing and/or casing and/or other communication techniques.

[0092] As described in greater detail herein, each of the downhole parameters and properties described herein may be measured by a downhole evaluation tool 102, communicated to the processing device 110, and used by the processing device 110 to, for example, control any of the operating parameters and properties of the well system 10 described herein, such as controlling the tunnel creation parameters described herein. For example, the techniques described herein may be performed or caused to be performed by the processing device 110 executing coded instructions 122. For example, the processing device 110 may receive data relating to any of the measured downhole parameters and properties from a downhole evaluation tool 102, and the processing device 110 may operate or cause a change in an operational parameter of one or more pieces of the wellsite equipment described herein based at least in part on the downhole measurements. In addition, the processing device 110 may receive information from a 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. FIG. 14 is a block diagram of at least a portion of a processing device 110 configured to execute instructions 122 to implement the techniques described herein. The processing device 110 may form at least a portion of one or more electronic devices utilized at the wellsite or located offsite.

[0093] In certain embodiments, the processing device 110 may be in communication with the downhole evaluation tool 102, as well as other sensors, actuators, controllers, and other devices of the well system 10. The processing device 110 may be operable to receive coded instructions 122 from human operators and sensor data generated by the downhole evaluation tool 102, as well as other sensors, process the coded instructions 122 and the sensor data, and communicate control data to local controllers and/or the actuators to execute the coded instructions 122 to implement at least a portion of the techniques described herein.

[0094] In certain embodiments, the processing device 110 may be or include, 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. In certain embodiments, the processing device 110 may include a processor 124, such as a general-purpose programmable processor. In certain embodiments, the processor 124 may include a local memory 126, and may execute coded instructions 122 present in the local memory 126 and/or another memory device. In certain embodiments, the processor 124 may execute, among other things, the machine-readable coded instructions 122 and/or other instructions and/or programs to implement the techniques described herein. In certain embodiments, the programs stored in the local memory 126 may include program instructions or computer program code that, when executed by the processor 124 of the processing device 110, may cause the well system 10 and/or other devices to perform the techniques described herein. In certain embodiments, the processor 124 may be, include, 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.

[0095] In certain embodiments, the processor 124 may be in communication with a main memory 128, such as may include a volatile memory 130 and a non-volatile memory 132, perhaps via a bus 134 and/or other communication means. In certain embodiments, the volatile memory 130 may be, include, 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. In certain embodiments, the non-volatile memory 132 may be, include, or be implemented by read-only memory, flash memory, and/or other types of memory devices. In certain embodiments, one or more memory controllers (not shown) may control access to the volatile memory 130 and/or non-volatile memory 132. [0096] In certain embodiments, the processing device 110 may also include an interface circuit 136, which may be, include, 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. In certain embodiments, the interface circuit 136 may also include a graphics driver card. In certain embodiments, the interface circuit 136 may also include 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.). In certain embodiments, one or more of the local controllers, the downhole evaluation tool 102, the other sensors, and the actuators of the well system 10 may be connected with the processing device 110 via the interface circuit 136, such as may facilitate communication between the processing device 110 and the local controllers, the downhole evaluation tool 102, the other sensors, and/or the actuators.

[0097] In certain embodiments, one or more input devices 138 may also be connected to the interface circuit 136. In certain embodiments, the input devices 138 may permit the human operators to enter the coded instructions 122, such as control commands, processing routines, operational settings and set-points. In certain embodiments, the input devices 138 may be, include, 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. In certain embodiments, one or more output devices 140 may also be connected to the interface circuit 136. In certain embodiments, the output devices 140 may be, include, 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. In certain embodiments, the processing device 110 may also communicate with one or more mass storage devices 142 and/or a removable storage medium 144, 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.

[0098] In certain embodiments, the coded instructions 122 may be stored in the mass storage device 142, the local memory 126, and/or the removable storage medium 144. Thus, the processing device 110 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 124. 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 124. In certain embodiments, the coded instructions 122 may include program instructions or computer program code that, when executed by the processor 124, may perform the processes and/or operations described herein.

[0099] The specific embodiments described above have been illustrated by way of example, and it should be understood that these embodiments may be susceptible to various modifications and alternative forms. It should be further understood that the claims are not intended to be limited to the particular forms disclosed, but rather to cover all modifications, equivalents, and alternatives falling within the spirit and scope of this disclosure.