CROSS REFERENCE TO RELATED APPLICATIONS
None.
FIELD OF THE INVENTION
Disclosed embodiments relate generally to methods and apparatuses for hydraulically fracturing a subterranean formation and more particularly to methods and apparatuses for hydraulically fracturing a subterranean formation while drilling and/or while tripping a drill string out of a well.
BACKGROUND INFORMATION
Wellbores are commonly drilled through subterranean formations to enable the extraction of hydrocarbons. Hydraulic fracturing is known to significantly increase the production rates of hydrocarbons in certain subterranean formation types (e.g., those having low fluid and/or gas permeability such as deep shale formations). In one common hydraulic fracturing operation, high pressure fluids are used to create localized fractures in the formation. The fluids may further include proppants (such as sand) to hold open the fractures after the pump pressure is removed thereby enabling hydrocarbons to flow from the fractured formation into the wellbore.
The overall process for creating a hydraulically fractured wellbore commonly includes two or three primary operations; a drilling operation, an optional casing operation, and hydraulic fracturing operations. These operations generally require distinct surface and downhole equipment (sometimes even including distinct surface rigging) and commonly make use of different engineering teams. The overall process to create a productive wellbore can therefore be time consuming and expensive as it commonly requires removing the drilling and casing equipment and moving in and rigging up the fracturing equipment in addition to performing the actual drilling, casing, and fracturing operations.
Therefore, there's a need in the art for improved overall process for creating a hydraulically fractured wellbore.
SUMMARY
Methods and apparatuses for hydraulically fracturing a subterranean wellbore are disclosed. In one embodiment a method for hydraulically fracturing a subterranean formation includes rotating a drill string in the subterranean wellbore to drill the wellbore and hydraulically fracturing the subterranean formation at a plurality of axially spaced locations along the wellbore while tripping the drill string out of the wellbore. The drill string includes a hydraulic fracturing assembly. The hydraulic fracturing operation includes translating the drill string in an uphole direction so that a set of frac ports in the hydraulic fracturing assembly is adjacent a region of the formation selected for fracturing, expanding at least one pair of packers to seal an annular region of the wellbore exterior to the frac ports, pumping fracturing fluid downhole through the frac ports to hydraulically fracture the subterranean formation. The hydraulic fracturing process may then be repeated at a plurality of axially spaced locations along the wellbore while tripping the drill string out of the wellbore.
The disclosed embodiments may provide various technical advantages. In particular, the disclosed methods may enable a significant time and cost savings to be realized when drilling and hydraulically fracturing a subterranean wellbore. The disclosed embodiments may further enable a rig having a smaller foot print to be utilized due to sharing of the surface equipment between the drilling and fracturing operations. The disclosed embodiments may further reduce crew requirements as field personnel may be cross trained to perform both drilling and fracturing operations.
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 key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
BRIEF DESCRIPTION OF THE DRAWINGS
For a more complete understanding of the disclosed subject matter, and advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:
FIG. 1 depicts one example of a conventional drilling rig on which the disclosed hydraulic fracturing assembly may be utilized in the disclosed methods may be practiced.
FIG. 2 depicts a lower BHA portion of the drill string shown on FIG. 1.
FIGS. 3A and 3B (collectively FIG. 3) example packers that may be used in the hydraulic fracturing assembly depicted on FIG. 28. The packers are contracted in FIG. 3A and expanded in FIG. 3B.
FIG. 3C depicts an alternative hydraulic fracturing assembly embodiment including a single (one) packer.
FIG. 4 depicts a block diagram of example surface equipment that may be utilized in the disclosed hydraulic fracturing while drilling and/or tripping methods.
FIG. 5 depicts a flow chart of one disclosed method embodiment.
FIGS. 6A-6C (collectively FIG. 6) depict a portion of the method shown in the flowchart on FIG. 5.
FIGS. 7A-7F (collectively FIG. 7) depict the remainder of the method shown in the flowchart on FIG. 5.
FIGS. 8A-8D (collectively FIG. 8) depict an alternative embodiments of the method shown in the flowchart on FIG. 5.
FIGS. 9A and 9B (collectively FIG. 9) depict a plan view of a multilateral wellbore configuration prior to (FIG. 9A) and after hydraulic fracturing (FIG. 9B).
FIG. 10 depicts a plot of measured depth versus time comparing a disclosed method of hydraulic fracturing while drilling and/or tripping versus a conventional drilling and fracturing operation.
FIG. 11 depicts a flow chart of another disclosed method embodiment.
FIGS. 12A and 12B (collectively FIG. 12) depict alternative drill string configurations for use in a combined hydraulic fracturing while casing drilling operation.
FIG. 13 depicts a flow chart of still another disclosed method embodiment.
DETAILED DESCRIPTION
FIG. 1 depicts a drilling rig 20 suitable for using various apparatus and method embodiments disclosed herein. The rig may be positioned over an oil or gas formation 28 disposed below the surface of the earth 25. The formation 28 may include substantially any suitable formation such as a horizontal Marcellus shale (the disclosed embodiments are of course not limited to horizontal formations).
The rig 20 may include a derrick and a hoisting apparatus for raising and lowering a drill string 30, which, as shown, extends into wellbore 40 and includes a drill bit 32, a number of downhole tools 52, 54, and 56, and a hydraulic fracturing assembly 100. The downhole tools 52, 54, and 56 may include substantially any suitable downhole tools, for example, including 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 the like. The disclosed embodiments are not limited in these regards. It will be understood by those of ordinary skill in the art that the deployment illustrated on FIG. 1 is merely an example.
FIG. 2 depicts the lower bottom hole assembly (BHA) portion of drill string 30. In the depicted example, the BHA further includes a steering tool 52 (such as a rotary steerable tool or a steerable motor), a logging while drilling tool 54 (e.g., employing sonic, nuclear, density, pressure, temperature, and/or resistivity sensors), and a measurement while drilling tool 56 (e.g., employing accelerometers and magnetometers for obtaining wellbore surveys). Hydraulic fracturing assembly 100 includes a plurality of inflatable or mechanical packers 120 deployed axially about one or more frac ports 130 which, when open are in fluid communication with a central through bore thereby enabling fracturing fluid to be injected into the annular region of a wellbore (which is intended to hydraulically fracture the adjacent formation). The frac ports 130 may be closed when drilling so that drilling fluid may be pumped to the bit. Under gauge stabilizers 140 are deployed between adjacent ones of the packers 120 and frac ports 130. The assembly 100) further includes a valve 110 (such as a digital valve) for directing drilling fluid or fracturing fluid to the drill bit 32 or the frac ports 130. When the valve 110 is open, the drill bit is in fluid communication with drilling fluid at the surface via a through bore in the drill string 30. Closing the valve 110 is intended to hydraulically isolate the drill bit from the surface such that full pressure fracturing fluid may be delivered to the frac ports 130. The valve 110 and frac ports 130 may be configured to operate in tandem such that the valve 110 is open on the front ports 130 are closed (and vice versa).
FIGS. 3A and 3B depict example packers 120 in the contracted (deflated) (FIG. 3A) and expanded (FIG. 3B) states. The packers 120 may include an external gouge-resistant coating 122 deployed about the inflatable member 124. When the packers are contracted (as in FIG. 3A) the outer surface thereof is radially recessed with respect to an outer surface of the under gauge stabilizers 140. Both the coating 122 and the stabilizers 140 are intended to protect the packers 120 during drilling. The gouge-resistant coating 122 may be configured to break or flake off the packers 120 in the first inflation (expansion) cycle as indicated at 126 on FIG. 3B. The coating 120 may also be removed chemically, for example, via circulating a chemical solution that degrades the coating. When the packers are expanded the outer surface thereof is intended to extend radially beyond the outer surface of the stabilizers 140 and into contact with a borehole wall thereby sealing the annular region about the frac ports 130.
It will be understood that the disclosed hydraulic fracturing assembly embodiments do not necessary include multiple packers as depicted on FIG. 2. FIG. 3C depicts an alternative embodiment in which a hydraulic fracturing assembly includes a single (one) packer 120 configured to isolate the annulus in combination with a chemical, gel, cement, or particulate (sand) packer 120′ that may be injected below the bit to form the isolated annular region about frac ports 130.
FIG. 4 depicts a block diagram of example surface equipment 150 that may be utilized in the disclosed hydraulic fracturing while drilling and/or fracturing while tripping methodologies. A pumping system 160 including one or more hybrid drilling fluid/fracturing fluid pumps is hydraulically coupled with a wellhead or a blowout preventer (BOP) 170. The pumping system 160 may be further hydraulically coupled with additional pumps 165 (e.g., conventional pumper trucks) for use in a hydraulic fracturing operation (as a fracturing operation may at times require more pressure than a conventional drilling operation). The pumping system 160 may optionally be further coupled with a cement blender (not shown) and used to pump cement downhole, for example, for casing wellbore sections above the reservoir. The pumping system may be still further hydraulically coupled with a three way valve 155 that is in turn hydraulically coupled with drilling fluid tanks 172, a flushing fluid (line flushing) tank 175, and a fracture fluid blender 180. The drilling fluid tanks 172 may include, for example, a conventional mud tank including a degasser, a desilter, a desander, and a shale shaker for removing various gaseous and solid phase impurities from the drilling fluid. The flushing fluid tank 175 may include, for example, a tank including an aqueous-based flushing fluid for flushing drilling fluid out of the system prior to the hydraulic fracturing operation. The blender 180 may be further hydraulically coupled to one or more fracture fluid containers 185, for example, including water and other chemical components as well as a proppant container 190 such as a sand truck.
FIG. 5 depicts a flow chart of one disclosed method embodiment 200. A subterranean wellbore is drilled through a formation of interest at 202, for example, using conventional directional drilling, logging while drilling, and measurement while drilling techniques. During the drilling process in 202 logging while drilling (formation evaluation) data may optionally be acquired and evaluated at 204 in order to precisely locate and tag (identify) locations for subsequent hydraulic fracturing (stimulation). At 206 the surface system and the bottom hole assembly may be reconfigured in preparation for the hydraulic fracturing operation (e.g., by flushing the drilling fluid out of the system and connecting the drill string to the fracturing fluid blender). The drill string is pulled off bottom at 208 such that the fracture port (or ports) are located adjacent a region (or regions) to be fractured. After inflating (or expanding) the packers and thereby sealing the annulus about the frac port(s), high pressure fracturing fluid is then pumped downhole at 210 to hydraulically fracture the selected region. After deflating (or contracting) the packers, the drill string may then be pulled further uphole to another location selected for fracturing. This process may be repeated substantially any number of times until all the selected regions have been fractured.
Method 200 is now described in further detail with respect to FIGS. 6A-C and FIGS. 7A-7F. FIGS. 6A-6C depict steps 202 and 204 of method 200 (FIG. 5). Wellbore 40 is drilled through a formation of interest 28 as indicated on FIG. 6A. Valve 110 is open as indicated and the frac ports are closed thereby allowing drilling fluid to flow to drill bit 32 as depicted at 220. Formation evaluation (logging while drilling) data may be obtained while drilling as indicated at 222. The formation evaluation data may be used to identify zones of interest for subsequent stimulation and hydraulic fracturing as indicated at 224 (FIG. 6B). The zones may be identified, for example, via noting a measured depth in a depth log and/or “tagging” the formation, for example, via a radioactive paint. The drilling operation continues as long as desired (e.g., to a predetermined measured depth) with the potential for a significant number of zones (e.g., 20 or more, 50 or more, or even 100 or more) being identified and tagged (two of such zones are depicted on FIG. 6C).
FIGS. 7A-7F depict steps 206, 208, and 210 of method 200 (FIG. 5). The drilling operation is completed (at least temporarily) as indicated on FIG. 7A. In optional embodiments a number of zones of interest 224 have been identified. At this time, the surface system may be reconfigured as described above in preparation for the hydraulic fracturing operation. The drill string may be lifted off bottom as indicated at 227 on FIG. 7B so that at least one set of frac ports 130 are aligned with a zone of interest. The frac ports may be opened to provide fluid communication for the fracturing fluid to enter the formation. Valve 110 may be closed as indicated at 226 thereby preventing fracturing fluid from flowing to the drill bit 32. At least a pair of packers 120 may be expanded to isolate a portion of the annulus as indicated 228 (FIG. 7C). Additional packers may optionally be inflated (expanded) to isolate multiple annular regions or to provide additional reinforcement and/or anchoring of the drill string. Additional packers may also be inflated (expanded) to assist with well control issues that may be encountered. Fracturing fluid may then be pumped downhole as indicated at 229 through the open frac ports in order to fracture the formation at the zone of interest (adjacent to the isolated annulus) as indicated at 231 on FIGS. 7C, 7D, and 7E.
In the depicted embodiment the hydraulic fracturing assembly includes first and second, upper and lower, sets of frac ports 130. It will be understood that in such embodiments (having multiple sets of frac ports) the zones of interest may be hydraulically fractured sequentially in a multistep operation as depicted on FIGS. 7D and 7E or simultaneously. When fractured sequentially (as depicted) a first set of frac ports may be open in a first fracturing step while a second set is closed (e.g., as depicted on FIG. 7D the lower set of frac reports are open while the upper set are closed). In a subsequent fracturing step the first set of frac ports may be closed while the second set is open (e.g., as depicted on FIG. 7E). When fractured simultaneously multiple sets of frac ports may be open simultaneously such that the fracturing fluid enters the formation at corresponding multiple zones of interest.
The decision regarding whether to fracture adjacent zones sequentially or simultaneously (and how many zones 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 assembly including multiple fracture ports and may therefore be suitable for simultaneous hydraulic fracturing (while a smaller rig may not). The decision may also depend upon the pump pressure required to propagate the fractures and the desired depth of such fractures. For certain formations or formation types (e.g., those requiring higher pressures) it may be advantageous to fracture the zones sequentially as depicted in FIGS. 7A-7E. Simultaneous hydraulic fracturing of multiple zones may generally lead to a faster fracturing operation and thus may sometimes be preferred (assuming adequate rigging and pumping capabilities are in place and assuming suitable formation fracturing can be achieved). In certain embodiments, a hydraulic fracturing assembly having up to five axially adjacent sets of fracture ports may be viable.
With continued reference to FIG. 5 and FIGS. 7A-7F, once the initial zone or zones of interest have been hydraulically fractured (either sequentially or simultaneously), the packers may be unset (deflated or partially deflated) and the drill string pulled further uphole to other zones of interest identified for fracturing. The above-described procedure may be repeated in this way substantially any number of times (e.g., 30 or more times) to obtain a wellbore 40 having a large number of fracture zones 231 (e.g., 60 or more) as indicated on FIG. 7F.
FIGS. 8A-8D depict an alternative embodiment of method 200 in which one of the packers may be used to seal a previously fractured zone. In this embodiment the hydraulic fracturing assembly 100′ includes first and second axially spaced packers and a single set of frac ports 13) deployed therebetween. In FIG. 8A the packers 120 are set and fracturing fluid is pumped through the frac ports 130 thereby hydraulically fracturing the formation as indicated at 242. The frac ports 130 may be closed and the packers 120 deflated (FIG. KB) thereby releasing the pressure in the fractured formation. It will be understood that the fractures remain partially open after the pressure is released due to the presence of proppant 243 (such as sand) in the fracturing fluid. The drill string may then be pulled uphole to another axial position such that when inflated the lower packer 120′ (or one of the lower packers in embodiments including multiple packers) seals the newly fractured zone as depicted on FIG. 8C. Fracturing fluid may then again be pumped through the frac ports thereby fracturing the formation at a second location as indicated at 244 on FIG. 8D. This process may be completed substantially any number of times so as to hydraulically fracture the formation of large number of locations.
While not depicted in flowchart 200, the method may optionally further include running a casing string into the drilled and hydraulically fractured wellbore. For example, slotted liners (casing) may be run in and deployed in the fractured regions (e.g., after the fracturing operation has been finished and the drill string removed the wellbore). The casing string may be supported in the wellbore by a plurality of modular swellable isolation packers (such as the ResPack available from Schlumberger) which may be formed from a polymer that swells in the presence of wellbore fluids. The casing string may alternatively be unsupported in the wellbore. Moreover, it will be understood that disclosed embodiments do not necessarily include a casing step. In certain embodiments the well plan may call for an open hole or barefoot completion (i.e., a completion not including a wellbore liner or casing).
FIGS. 9A and 9B depict plan views of a multilateral wellbore configuration including a substantially vertical pilot well 252 and multiple deviated lateral wellbores 254. In the depicted embodiment, each of the multiple lateral wellbores 254 may be drilled and fractured using hydraulic fracturing assembly 100 or 100′ and fracturing methodology 200 described above with respect to FIGS. 2 and 4-8. For example, lateral wellbore 254A may be drilled and hydraulically fractured back to junction 256 using the above-described procedure. Lateral wellbore 254A may optionally then be temporarily sealed, for example, using a packer or a cement or gel plug (e.g., as depicted at 120′ on FIG. 3A). Lateral wellbores 254B and 254C may then be drilled and hydraulically fractured using a similar procedure. After fracturing lateral wellbores 254B and 254C, lateral wellbore section 254D may also be fractured. The other depicted multilateral wellbores may then be similarly drilled and fractured from the pilot well 252.
FIG. 9B depicts the multilateral wellbores including the stimulated hydraulic fractures 258. In the depicted embodiment the fractures are shown to generally propagate in the same direction (typically along the direction of maximum formation stress). In certain embodiments the direction of maximum formation stress may be measured while drilling (prior to fracturing), for example, using acoustic or nuclear logging while drilling measurements. These measurements may then be used to evaluate (or predict) the direction and extent of the hydraulic fractures during the fracturing operation. Moreover, such LWD measurements taken in either the pilot hole 252 or the first lateral 254A may be used to determine the direction of subsequent laterals. Knowing the stress direction allows the laterals to be placed in an azimuthal direction to optimize the placement of hydraulic fracturing treatments. Furthermore, the LWD measurements may also be used to make on the fly adjustments to the multilateral wellbore plan so as to optimize drainage based on predicted fracture propagation. For example, the direction and/or spacing of the multilateral wells may be adjusted on the fly (while drilling and/or fracture) based on the logging while drilling measurements in the predicted fracture propagation characteristics.
One advantage of the disclosed methods is that they tend to significantly reduce the time to first production (and therefore tend to also provide significant cost savings in bringing a wellbore to production). FIG. 10 depicts a plot of measured depth versus time for an example method disclosed herein and a conventional drilling and fracturing operation. The example drilling operation is depicted by the solid line at 402. In the depicted embodiment, a multistage drilling operation is employed (including first, second, and third stages 402A, 402B, and 402C in this example although the disclosed embodiments are by no means limited in this regard). Corresponding time delays 404A and 404B are depicted between the multiple drilling stages and represent, for example, the time required to trip out the drill string and trip in a new drill string including a modified BHA (e.g., having a new drill bit).
A conventional hydraulic fracturing operation is depicted by the dotted line at 410. This operation includes an extended time delay at 412 (also referred to in the art as downtime or flat time). This time delay represents the time required to break down the drilling equipment and drilling rig (and perhaps move it off location) and then the time required to move in and rig up the fracturing equipment (including the rigging, the fracturing fluid pumps, and the fracturing fluid holding and blending systems) used in the conventional fracturing operation. A single entry multizone fracturing operation is depicted at 414. In this operation multiple fractures are imparted to the portion of the wellbore represented by the third stage 402C. The conventional multizone hydraulic fracturing assembly is then removed from the wellbore upon the completion of the operation at 416.
The disclosed fracturing methodology is depicted by the dashed line at 420. This operation includes a comparatively short time delay 422 in which the surface system is reconfigured for pumping fracturing fluid downhole (this may be as simple as opening and/or closing one or more valves (such as valve 155 on FIG. 4) and flushing the pumps and drill string with a line flushing fluid). The multistage fracturing operation is depicted at 424 and again depicts an operation in which multiple fractures are imparted to the third stage 402C of the wellbore. The drill string is then removed from the wellbore (tripped out) at 426. The overall time savings is shown at 430 and in this particular example represents the time difference between delays 412 and 422 (the conversion times required to change over from a drilling operation to a fracturing operation).
It will be understood that the time savings 430 depicted on FIG. 10 can represents a significant cost savings since drilling and fracturing operations are commonly estimated to represent about 50% of the final well cost and about 30% of the final well time. These cost savings may be realized, for example, as reduced labor costs, equipment rental costs, facilities costs, and service costs. Moreover, depending on the operation, there may be a reduction in costs associated with eliminating certain services such as perforating operations intended to perforate a casing string and cementing operations intended to cement a casing string in the wellbore. In one example the disclosed methodology has been projected to yield a total savings of $1.2 million for drilling and fracturing a wellbore in a Marcellus shale formation in which the authority for expenditure (AFE) is $5.6 million (a savings rate of 21%).
FIG. 1 depicts a flow chart of another disclosed method embodiment 300. A subterranean wellbore is drilled through a formation of interest at 202, for example, using conventional directional drilling, logging while drilling, and measurement while drilling techniques (as described above with respect to method 200 and FIG. 5). During the drilling process in 202 logging while drilling (formation evaluation) data may optionally be acquired and evaluated at 204 in order to precisely locate and/or tag (identify) locations for subsequent fracturing (stimulation). After the drilling operation has been finished, the drill string may be tripped out of the wellbore at 306 and the drill bit (and possibly other BHA components) replaced with a hydraulic fracturing assembly such as hydraulic fracturing assembly 100 or 100′ depicted on FIGS. 2 and 8. At 308 the surface system may be reconfigured in preparation for the fracturing operation, for example, as described above at 206 of FIG. 5. Such reconfiguring at 308 may advantageously be performed while the drill string is being tripped out of the wellbore at 306. The drill string (with the hydraulic fracturing assembly deployed thereon) may be tripped back into the well at 310 such that the fracture port (or ports) are located adjacent a region (or regions) to be fractured (e.g., one or more of the regions tagged at 202). After inflating the packers, high pressure fracturing fluid may then be pumped downhole at 312 to fracture the selected region. After deflating the packers, the drill string may then be moved to another location selected for fracturing. This process may be repeated substantially any number of times until all the selected regions have been fractured. It will be understood that while the time savings and cost savings provided by method 300) may be less than that of method 200 (owing to the time required to trip the drill string out of and back into the wellbore), the savings can nonetheless be significant (e.g., on the order of about 10% of the total AFE).
FIGS. 12A and 12B depict alternative drill string configurations that may be used in combined hydraulic fracturing while casing and drilling operations. In FIG. 12A the drill string includes a casing string 410. The BHA extends out of the lower end of the casing string and includes a drill bit 32, a steering tool 52, and optional LWD 54 and MWD 56 tools as described above with respect to FIG. 2. The BHA further includes a hydraulic fracturing assembly 430 such as assembly 100 or 100′ described above with respect to FIGS. 2 and 8. The drill string may further include a mud motor 410 deployed in the lower end of the casing string as well as stabilizers 440 and a drilling lock assembly (shown schematically at 445) deployed in the casing string. One example of drilling lock assembly is described in more detail in U.S. Patent Publication 2010/0126734.
FIG. 12B depicts a drill string configuration similar to that shown on FIG. 12A in that a BHA extends out of the lower end of the casing string and includes a drill bit 32, a steering tool 52, and optional LWD 54 and MWD 56 tools as described above with respect to FIG. 2. In this embodiment, the hydraulic fracturing assembly 430 is deployed in the lower section of casing string 420. Casing string 420 differs from casing string 410 in that it includes perforations 425 at which the formation may be fractured using the internal hydraulic fracturing assembly. Although not depicted on FIG. 12B, a mud motor, stabilizers, and a drilling lock assembly may be deployed in the casing string, for example, above the hydraulic fracturing assembly 430.
FIG. 13 depicts a flow chart of still another disclosed method embodiment 450, in this case, for fracturing while drilling and casing. Method 450 may employ, for example, one of the drill string configurations depicted on FIGS. 12A and 12B. A subterranean wellbore is drilled through a formation of interest at 452, for example, using a drill string including a casing while drilling assembly (e.g., as described above) and a hydraulic fracturing assembly (such as also described above). After the drilling operation has been completed, the surface system and the bottom hole assembly may be reconfigured at 454 (e.g., as described above at 206 of FIG. 5) in preparation of the fracturing operation. The drill string may be translated upward at 456 such that the frac ports in hydraulic fracturing assembly 430 are located adjacent a region of the formation that is to be fractured. After inflating the packers, high pressure fracturing fluid may then be pumped downhole at 458 to fracture the selected region. In embodiments in which the hydraulic fracturing assembly is located inside the casing string (e.g., as depicted on FIG. 12), the fracturing fluid may be pumped outward through the preformed perforations in the casing. The casing may then be released from the drill string and deployed in the wellbore having the fractured formation at 460. The BHA may then be moved to another location selected for fracturing (e.g., to another location where perforations have been formed in the casing). This process may be repeated substantially any number of times until all the selected regions have been fractured.
Although fracturing while drilling and/or tripping 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.
Patent Application
20160053597
