10,000-Psi Multilateral Fracking System with Large Internal Diameters for Unconventional Market

This application is a divisional of U.S. application Ser. No. 17/833,617, filed on Jun. 6, 2022, entitled “10,000-PSI MULTILATERAL FRACKING SYSTEM WITH LARGE INTERNAL DIAMETERS FOR UNCONVENTIONAL MARKET,” which claims priority to U.S. Application Ser. No. 63/197,886, filed on Jun. 7, 2021, entitled “12,000-PSI MULTILATERAL FRACKING SYSTEM WITH LARGE INTERNAL DIAMETERS FOR UNCONVENTIONAL MARKET (AKA DEVICE, SYSTEM AND METHOD FOR FRACKING HIGH-PRESSURE WELLS WITHOUT A DRILLING RIG),” U.S. Application Ser. No. 63/197,945, filed on Jun. 7, 2021, entitled “MULTILATERAL WELL TOOLS THAT PASS THROUGH SMALLER RESTRICTIONS,” and U.S. Application Ser. No. 63/197,924, filed on Jun. 7, 2021, entitled “SPACER WINDOW SLEEVE,” all of which are commonly assigned with this application and incorporated herein by reference in their entirety.

In the production of hydrocarbons, it is common to drill one or more secondary wellbores from a first wellbore. Typically, the first and secondary wellbores, collectively referred to as a multilateral wellbore, will be drilled and/or cased using a drilling rig. Thereafter, once completed, the drilling rig will be removed, and the wellbores will produce hydrocarbons.

During any stage of the life of a wellbore, various treatment fluids may be used to stimulate the wellbore. As used herein, the term “treatment,” or “treating,” refers to any subterranean operation that uses a fluid in conjunction with a desired function and/or for a desired purpose. The term “treatment,” or “treating,” does not imply any particular action by the fluid or any particular component of the fluid.

One common stimulation operation that employs a treatment fluid is hydraulic fracturing. Hydraulic fracturing operations generally involve pumping a treatment fluid (e.g., a fracturing fluid) into a wellbore that penetrates a subterranean formation at a sufficient hydraulic pressure to create one or more cracks, or “fractures,” in the subterranean formation through which hydrocarbons will flow more freely. In some cases, hydraulic fracturing can be used to enhance one or more existing fractures. “Enhancing” one or more fractures in a subterranean formation, as that term is used herein, is defined to include the extension or enlargement of one or more natural or previously created fractures in the subterranean formation. “Enhancing” may also include positioning material (e.g., proppant) in the fractures to support (“prop”) them open after the hydraulic fracturing pressure has been decreased (or removed).

During the initial production life of a wellbore—often called the primary phase—primary production of hydrocarbons typically occurs either under natural pressure, or by means of pumps that are deployed within the wellbore. This may include wellbores that have undergone stimulation operations, such a hydraulic fracturing, during a completion process. Unconventional wells typically will not produce economical amounts of oil or gas unless they are stimulated via a hydraulic fracturing process to enhance and connect existing fractures. In order to reduce well costs, the hydraulic fracturing process is performed after the drilling rig has been removed from the well. Furthermore, wells may be hydraulically fractured without the aid of a workover rig if the equipment used to fracture a well is light enough to be transported in and out of the wellbore via a coiled tubing unit, wireline, electric line, or other device.

Over the life of a wellbore, the natural driving pressure may decrease to a point where the natural pressure is insufficient to drive the hydrocarbons to the surface given the natural permeability and fluid conductivity of the formation. At this point, the reservoir permeability and/or pressure must be enhanced by external means. In secondary recovery, treatment fluids are injected into the reservoir to supplement the natural permeability. Such treatment fluids may include water, natural gas, air, carbon dioxide or other gas and a proppant to hold the fractures open.

Likewise, in addition to enhancing the natural permeability of the reservoir, it is also common through tertiary recovery, to increase the mobility of the hydrocarbons themselves in order to enhance extraction, again through the use of treatment fluids. Such methods may include steam injection, surfactant injection and carbon dioxide flooding.

In both secondary and tertiary recovery, hydraulic fracturing may also be used to enhance production.

Depending on the nature of the secondary or tertiary operation, it may be necessary to redeploy a rig, often referred to as a “workover rig,” to the wellbore to assist in these operations, which may require additional equipment be installed in a wellbore. For example, subjecting a producing wellbore to hydraulic fracturing pressures after it has been producing may damage certain casings, installations, or equipment already in a wellbore. Thus, it may be necessary to install additional equipment to protect the various equipment and tools already in the wellbore before proceeding with such operations. Such additional equipment is typically of sufficient size and weight that requires the use of a workover rig. As the number of secondary wellbores in a multilateral wellbore increases, the difficulty in protecting the various equipment in the first wellbore and the secondary wellbores becomes even more pronounced.

It would be desirable to provide a system that avoids the need for drilling or workover rigs in treatment fluid operations in multilateral wellbores, particularly those subject to stimulation techniques such as hydraulic fracturing.

The disclosure may repeat reference numerals and/or letters in the various examples or FIGs. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Further, spatially relative terms, such as beneath, below, lower, above, upper, uphole, downhole, upstream, downstream, and the like, may be used herein for ease of description to describe one element or feature's relationship to another element(s) or feature(s) as illustrated, the upward direction being toward the top of the corresponding FIG. and the downward direction being toward the bottom of the corresponding FIG., the uphole direction being toward the surface of the wellbore, the downhole direction being toward the toe of the wellbore. Unless otherwise stated, the spatially relative terms are intended to encompass different orientations of the apparatus in use or operation in addition to the orientation depicted in the FIGs. For example, if an apparatus in the FIGs. is turned over, elements described as being “below” or “beneath” other elements or features would then be oriented “above” the other elements or features. Thus, the exemplary term “below” can encompass both an orientation of above and below. The apparatus may be otherwise oriented (rotated 90 degrees or at other orientations) and the spatially relative descriptors used herein may likewise be interpreted accordingly.

Moreover, even though a FIG. may depict a horizontal wellbore or a vertical wellbore, unless indicated otherwise, it should be understood by those skilled in the art that the apparatus according to the present disclosure is equally well suited for use in wellbores having other orientations including vertical wellbores, deviated wellbores, multilateral wellbores, or the like. Likewise, unless otherwise noted, even though a FIG. may depict an offshore operation, it should be understood by those skilled in the art that the apparatus according to the present disclosure is equally well suited for use in onshore operations and vice-versa. Further, unless otherwise noted, even though a FIG. may depict a cased hole, it should be understood by those skilled in the art that the apparatus according to the present disclosure is equally well suited for use in open hole operations.

As used herein, “first wellbore” shall mean a wellbore from which another wellbore extends (or is desired to be drilled, as the case may be). Likewise, a “second” or “secondary” wellbore shall mean a wellbore extending from another wellbore. The first wellbore may be a primary, main or parent wellbore, in which case, the secondary wellbore is a lateral or branch wellbore. In other instances, the first wellbore may be a lateral or branch wellbore, in which case the secondary wellbore is a “twig” or a “tertiary” wellbore.

Generally, in one or more embodiments, a frac window system is provided in a multilateral wellbore with a secondary wellbore extending from a first wellbore. The frac window system includes a tubular having an opening therein that aligns with a secondary wellbore window formed in the casing string of the first wellbore. The frac window system may include annular seals along the outer surface of the tubular above and below the opening, and may further include an orientation device carried within the tubular.

In one or more embodiments, an isolation sleeve (e.g., a main bore isolation sleeve) is positioned within the frac window system to seal the opening in the frac window system and the secondary wellbore window in the first wellbore casing to isolate the secondary wellbore from high pressure fluid directed farther down the first wellbore casing.

In one or more alternative embodiments, a whipstock may seat on an orientation device so that a surface of the whipstock is aligned with the secondary wellbore window of the first wellbore casing string. In one or more embodiments, a straddle stimulation tool abuts the surface of the whipstock and extends through the frac window system opening from the first wellbore into the secondary wellbore, thereby providing the high pressure fluid to the secondary wellbore. In one or more embodiments, a plug may also be used to isolate the primary wellbore from the high pressure fluid directed to the secondary wellbore.

Turning to, shown is an elevation view in partial cross-section of a frac window systemdeployed in a well system(land based inand offshore in) utilized to produce hydrocarbons from wellboreextending through various earth strata in a petroleum formationlocated below the earth's surface. Wellboremay be formed of a single first wellbore and may include one or more second or secondary wellbores,. . ., extending into the formation, and disposed in any orientation and spacing, such as the horizontal secondary wellbores,illustrated.

Well systemincludes a drilling rig or derrick. Drilling rigmay include a hoisting apparatus, a travel block, and a swivelfor raising and lowering a conveyance such as tubing string. Other types of conveyances may include tubulars such as casing, drill pipe, coiled tubing, production tubing, and other types of pipe or tubing strings. Still other types of conveyances may include wirelines, slicklines, and the like. In, tubing stringis a substantially tubular, axially extending work string formed of a plurality of drill pipe joints coupled together end-to-end, while in, tubing stringis completion tubing supporting a completion assembly as described below. Drilling rigmay include a kelly, a rotary table, and other equipment associated with rotation and/or translation of tubing stringwithin a wellbore. For some applications, drilling rigmay also include a top drive unit.

Drilling rigmay be located proximate to a wellheadas shown in, or spaced apart from wellhead, such as in the case of an offshore arrangement as shown in. One or more pressure control devices, such as blowout preventers (BOPs) and other equipment associated with drilling or producing a wellbore may also be provided at wellheador elsewhere in the well system.

For offshore operations, as shown in, whether drilling or production, drilling rigmay be mounted on an oil or gas platform, such as the offshore platformas illustrated, or on semi-submersibles, drill ships, and the like (not shown). Well systemofis illustrated as being a marine-based production system. Likewise, well systemofis illustrated as being a land-based production system. In any event, for marine-based systems, one or more subsea conduits or risersextend from deckof platformto a subsea wellhead. Tubing stringextends down from drilling rig, through riserand BOPinto wellbore.

A fluid source, such as a storage tank or vessel, may supply a working or service fluidpumped to the upper end of tubing stringand flow through tubing string. Fluid sourcemay supply any fluid utilized in wellbore operations, including without limitation, drilling fluid, cementious slurry, acidizing fluid, liquid water, steam, hydraulic fracturing fluid or some other type of fluid.

Wellboremay include subsurface equipmentdisposed therein, such as, for example, the completion equipment illustrated in. In other embodiments, the subsurface equipmentmay include a drill bit and bottom hole assembly (BHA), a work string with tools carried on the work string, a completion string and completion equipment or some other type of wellbore tool or equipment.

Well systemmay generally be characterized as having a pipe system. For purposes of this disclosure, pipe systemmay include casing, risers, tubing, drill strings, completion or production strings, subs, heads or any other pipes, tubes or equipment that attaches to the foregoing, such as tubing stringand riser, as well as the wellbore and laterals in which the pipes, casing and strings may be deployed. In this regard, pipe systemmay include one or more casing stringsthat may be cemented in wellbore, such as the surface, intermediate and production casing stringsshown in. An annulusis formed between the walls of sets of adjacent tubular components, such as concentric casing stringsor the exterior of tubing stringand the inside wall of wellboreor casing string, as the case may be.

As shown in, where subsurface equipmentis illustrated as completion equipment, disposed in secondary wellboreis a lower completion assemblythat includes various tools such as an orientation and alignment subassembly, a packer, a sand control screen assembly, a packer, a sand control screen assembly, a packer, a sand control screen assemblyand a packer.

Extending uphole and downhole from lower completion assemblyis one or more communication cables, such as a sensor or electric cable, that passes through packers,andand is operably associated with one or more electrical devicesassociated with lower completion assembly, such as sensors positioned adjacent sand control screen assemblies,,or at the sand face of formation, or downhole controllers or actuators used to operate downhole tools or fluid flow control devices. Cablemay operate as communication media, to transmit power, or data and the like between lower completion assemblyand an upper completion assembly.

In this regard, disposed in wellbore, the upper completion assemblyis coupled at the lower end of tubing string. The upper completion assemblyincludes various tools such as a packer, an expansion joint, a packer, a fluid flow control moduleand an anchor assembly.

Extending uphole from upper completion assemblyare one or more communication cables, such as a sensor cable or an electric cable, which passes through packers,and extends to the surface. Cable(s)may operate as communication media, to transmit power, or data and the like between a surface controller (not pictured) and the upper and lower completion assemblies,.

Fluids, cuttings, and other debris returning to surfacefrom wellboremay be directed by a flow lineback to storage tanks, fluid sourceand/or processing systems, such as shakers, centrifuges, and the like.

In each of, a frac window systemis generally illustrated. Frac window systemis positioned adjacent secondary wellboreso that an openingin the frac window systemis aligned with the casing windowof casing stringadjacent secondary wellbore

is an elevation view in cross-section of the first wellboreand the upper and lower secondary wellbores,and, respectively, illustrated as extending from first wellborein more detail. Specifically, the first wellboreis illustrated as being at least partially cased with a first wellbore casingcemented therein. While generally illustrated as vertical, first wellbore, as well as any of the wellbores described, may have any orientation. In any event, at the distal endof first wellbore, a casing hangermay be deployed from which a secondary wellbore casinghangs. Secondary wellbore casinghas a proximal endand a distal end. The proximal endmay include a shoulderfor supporting secondary wellbore casingon hanger. The distal endmay include perforationsor sliding sleeves. Secondary wellbore casingis illustrated as cemented in place within wellbore. Proximal endmay also include a polished bore receptacle (PBR), which may be positioned above liner hanger. PBRmay have a larger inner diameter than the secondary wellbore casing. This prevents a seal(see) from creating a restriction smaller than the casinginner diameter.

Likewise, with regard to secondary wellbore, which is formed at a junctionwith first wellbore, a transition jointextends from a casing windowformed along the inner annulus of casing. Transition jointmay be made of steel, fiberglass, or any material capable of supporting itself under the pressure of fluids, cement, or solid objects such as rock in a downhole environment. A casing hangermay be deployed from which a secondary wellbore casinghangs. Secondary wellbore casinghas a proximal endand a distal endb and an interior surface. The distal endmay include perforationsor sliding sleeves. The proximal endmay include a shoulderfor supporting casingon hanger. Secondary wellbore casingis illustrated as cemented in place within wellbore. In other embodiments (not shown) the transition jointmay be threaded directly to a PBR, which in turn is threaded to the secondary wellbore casing, and no casing hangeris necessary.

Persons of ordinary skill in the art will appreciate that the illustrated first wellboreand secondary wellbores,, and the equipment illustrated therein, are for illustrative purposes only, and are not intended to be limiting. For example, secondary wellbore casing strings,are not limited to a particular size or manner of support, and other systems for supporting secondary wellbore casing may be utilized.

Any one or more of the casing strings or tubulars described herein may include an engagement mechanismdeployed along an inner surface and disposed to engage a cooperating engagement mechanism, such as engagement mechanism() described below, to secure or otherwise anchor adjacent tubulars relative to one another at a desired depth and/or orientation. In one or more embodiments, engagement mechanismmay be latch couplings as are shown deployed along first wellbore casing. In one or more embodiments, an engagement mechanismis positioned adjacent to windowat a known distance. In one or more embodiments, an engagement mechanismis positioned adjacent windowupstream or above junction, while in other embodiments, the engagement mechanism is positioned adjacent windowdownstream or below junction. The disclosure is not limited to a particular type of engagement mechanism.

Similar to engagement mechanism, an engagement mechanismis illustrated along the interior surfacei of casing.

Turning to, an elevation view in cross section illustrates the frac window systemdeployed adjacent junctionwithin first wellbore casing. Frac window systemis formed of an elongated tubularhaving a first endand a second endwith an openingdefined in a wallof the tubular between ends,. The elongated tubularmay extend a significant distance, and may be constructed of multiple casing, tubing, or other pipe without departing from the scope and spirit of the disclosure. Elongated tubularincludes an inner surfaceand an outer surface.

An orientation deviceis disposed or otherwise formed along the inner surfaceof elongated tubular. In one or more embodiments, orientation deviceis located below the opening, between opening theand the second endof elongated tubular. Although orientation devicemay be any mechanism or device that permits rotational orientation of a tool or equipment within elongated tubular, in one or more embodiments, orientation devicemay be a scoop head, a muleshoe or a ramped or angled surface. In yet another embodiment, the orientation deviceis located above the opening.

Frac window systemfurther includes a first sealdisposed along the outer surfaceof the elongated tubular. In one or more embodiments, first sealis disposed along the outer surfacebetween the openingand the first endof the elongated tubular. Likewise, a second sealis disposed along the outer surfacebelow openingbetween openingand the second endof elongated tubular. First sealextends between frac windowand casingto seal the annular spacetherebetween. Likewise, second sealextends between the outer surfaceof the elongated tubularand an inner surface of the adjacent tubular, e.g., first wellbore casing, to seal the annular space about the second endof elongated tubular. In the illustrated embodiment, second endextends into proximal endof secondary wellbore casing, and in such case, second sealseals the annular space therebetween. In other embodiments, second sealmay be disposed along the end ofof elongated tubularto seal between frac window systemand the first wellbore casing, and in particular, in some embodiments, PBR. In other embodiments, second sealmay be disposed along the inner surfaceof the elongated tubularat the second end ofto seal between frac window systemand a tubular (not shown) extending therein.

Seals,as described may be any mechanism that can seal an annular space between tubulars, such as for example an expandable liner hanger system, swellable elastomer or otherwise, any type of, or combination of, elastomeric element(s) or composite elements made of man-made and/or natural materials that may be deployed to effectuate a sealing contact with both tubulars as described. A seal may include a shoulder, such as shoulderformed along the outer surfaceof elongated tubular. The elongated tubularmay include a plurality of joints of pipe spanning the distance between the shoulderand smooth sealing surfacesmay also be provided along the inner surfaceof the elongated tubular. The shouldermay engage a similarly formed shoulder, such as the end of secondary wellbore casing, against which shouldermay seat, forming a metal-to-metal seal. Although not limited to a particular configuration, the most common place shoulderwould engage is in the PBRattached to hanger. This would typically be an “anchor” type of mechanism wherein shoulderwould have a releasable anchoring device such as a latch, a lug, a snap or similar mechanism, to attach itself to the top of the PBRor to the top of hanger. The top of PBRor the top of hangermay include a receiving head, a lug-receiver, a snap locator, or other device to receive, releasably secure, and/or provide a sealing surface for shoulder, and/or sealand/or endof elongated tubular. The disclosure is not limited to a particular type of mechanism that can seal an annular space between tubulars.

In other embodiments, shouldermay be disposed along the inner surfaceof end ofof elongated tubularto engage a similarly formed shoulder, such as the end of secondary wellbore casing.

Frac window systemmay further include an engagement mechanismalong outer surfaceand disposed for engagement with an engagement mechanism. In one or more embodiments, engagement mechanismis a latch and engagement mechanismis a latch coupling.

In one or more embodiments, engagement mechanismmay be an Engagement. Orientation, and Depth (EOD) device that provides depth, orientation, and an engagement into an accepting device. The engagement device of the EOD may be one that is releasable. The EOD may provide depth, orientation, and releasable engagement in concert with a device such as engagement mechanismor engagement mechanismor against a surface of a pipe or other device having a generally circular form and an inner and outer surface. In further embodiments, engagement mechanismmay be a collet. In other embodiments, engagement mechanismmay be a multiplicity of collets, keys, slips, latches, etc. Engagement mechanismmay also consist of multiple devices to provide depth, orientation and/or engagement such as collets, keys, slips, and/or latches, etc. Thus, for example, the engagement mechanismin the form of an EOD may be mounted on the outer surfaceof the elongated tubularfor engagement with an engagement mechanism, such as a latch coupling, disposed along the interior annulus of the first wellbore casing. In one or more embodiments, the engagement mechanismof the casingis above window, and the EODof frac window systemis between the openingand first endof the tubular. In one or more embodiments, the EODis between the first sealand the first endof the tubular. It will be appreciated that in one or more embodiments, engagement mechanismmay function to releasably engage another engagement mechanism, such as engagement mechanismor; function as a no-go shoulder (depth lock or stop) at a desired depth; and provide an orientation lock at a desired orientation.

In any event, regardless of the particular type, in one or more embodiments, although engagement mechanismmay be disposed anywhere along the outer surfaceso long as the axial position between frac window systemand windowis established, engagement mechanismis disposed between the openingand the first endto engage an engagement mechanismupstream of window, as illustrated. In one or more embodiments, the engagement mechanismis between the first sealand the first endso that the engagement mechanismmay be isolated from pressurized fluid that may be introduced into one of the secondary wellbores,. In another embodiment, the latchis placed below the window opening(e.g., a downhole end of the window opening) and the distal end

As will be appreciated, when engagement mechanismis a latch and engagement mechanismis a latch coupling, cooperation between the two mechanism,can be utilized to both axially and radially position frac window system. However, in one or more embodiments, engagement mechanismneed not be present. Rather, engagement mechanismmay be another type of device or mechanism to secure and/or position frac window systemin wellbore. In one or more embodiments, engagement mechanismmay be an expandable liner hanger carried on the outer surfaceof elongated tubular. Alternatively, or in addition, engagement mechanismmay be one or more slips that can be actuated to anchor against the first wellbore casing (or the wall of first wellborein the instance of an uncased wellbore). In one or more embodiments, engagement mechanismmay be one or more collets. In other embodiments,may be a multiplicity of collets, keys, slips, latches, pockets, grooves, recesses, indentations, slots, splines, etc. Also, mechanismmay consist of multiple devices to provide depth, orientation and/or engagement such as collets, keys, slips, and/or latches, etc. The disclosure is not limited to a particular type of engagement mechanism. Alternatively, or in addition, in one or more embodiments, engagement mechanismmay be, or work in concert with, a mechanically, hydraulically, and/or electrically activated window finder deployed within elongated tubularthat will actuate and extend at least partially through openingand windowwhen the openingand casing windoware aligned. In such case, it will be appreciated, with the relative alignment achieved, another engagement mechanism, such as an expandable liner hanger or slips, may be actuated to anchor elongated tubularin position.

It will be appreciated that latchand latch couplingpermit frac window systemto be axially and radially oriented so that frac window systemis adjacent junction, and thus window, and that openingis aligned with windowof casing.

Frac window systemmay further include a first depth mechanismdisposed along the inner surface. In one or more embodiments, the first depth mechanismis between the openingand the first endof elongated tubular. Similarly, a depth mechanismmay be disposed along the inner surfaceadjacent the orientation device.

When deployed as described above, openingof frac window systemis aligned with windowof casingand the annulus about elongated tubularis sealed above and below window. In one or more embodiments, openingof frac window systemhas a dimension Lthat is smaller than the dimension Lof window.

One or more of the inner or outer surfaces of elongated tubularadjacent the ends,may be threaded to assist in deployment of elongated tubular. For example, the inner surfaceof elongated tubularadjacent first endmay be threaded while the inner surfaceadjacent second end, as well as the outer surfaceadjacent the two ends,may be smooth, the threads disposed to permit attachment of a running tool (not shown). However, in one or more embodiments, the inner and outer surfaces,adjacent the ends,are all sufficiently smooth to permit an elastomeric element to seal against the surface. Thus, as used herein, “smooth” is used to refer to a surface that is not threaded. The smooth surface may have other shapes, features or contours, but is not otherwise disposed to engage the threads of another mechanism in order to join the mechanism to the surface. Other smooth sealing surfacesmay also be provided along the inner surfaceof the elongated tubularto ensure a desired level of sealing during operations employing frac window system.

The present disclosure has recognized that one of the roadblocks from fracking multilateral wells is the necessity of utilizing a drilling rig during the fracking operations. A frac window system designed, manufactured and operated according to the novel aspects of this disclosure, such as the frac window system, allows the drilling rig to be moved off of the well and coiled tubing to be utilized for substantially all (or all) frac operations. For example, a frac window system designed, manufactured and/or operated according to the novel aspects of this disclosure allows high rate, high-pressure through workstring/production tubing. For example, a frac window system designed, manufactured and/or operated according to the novel aspects of this disclosure may be capable of withstanding the high-pressures and stresses of stimulating at pressures of at least 5,000-psi, at least 10,000-psi, at least 12,500-psi and/or at least 15,000-psi. In some highly specialized situations, it may be desirable to be able to withstand pressures of 30,000-psi or more. For example, fracking of >80 BPM at 12,500-psi is achievable.

In some embodiments, it may be desirable to use wireline tools to perforate a portion of a wellbore (e.g.,in linerin wellboreand/orinin wellbore). As a rule of thumb, wireline tools (electric line, slick line, braided line, cable line, sand line, etc.) cannot move downhole solely due to gravity in wellbores with an inclination of greater than 65-degrees. For that reason, devices may be attached to the wireline so the wireline can be pumped downhole—fluid pressure is applied at the surface to pump the device and wireline downhole.

Accordingly, a frac window system designed, manufactured and/or operated according to the novel aspects of this disclosure may be manufactured of certain materials, and may have certain sidewall thicknesses and inside diameters, which would allow it to withstand the foregoing high-pressures. For example, wherein traditional frac window systems might comprise lower cost low alloy steels (e.g., L-80 material, K-55 material, etc.) that are only rated up to 5,000-psi, a frac window system according to the present disclosure would comprise high-strength materials that are greater than 5,000-psi rated, if not greater than 10,000-psi rated, if not greater than 12,500-psi rated, if not greater than 15,000-psi rated, or even up to 30,000-psi rated. In at least one embodiment, a frac window system according to the disclosure includes materials having a minimum yield strength of at least 110-ksi, if not at least 125-ksi, if not at least 140-ksi, among others. For example, a Q125 steel could be used for at least a portion of the frac window system and remain within the scope of the disclosure.