SYSTEM, METHOD, AND APPARATUS FOR MULTI-STAGE COMPLETION

Abstract

Systems and methods for completing a well, involving a fracture placement packer assembly comprising an inflatable packer positioned on an uphole side of the assembly; the inflatable packer is structured to execute repeated inflation/deflation cycles in response to an inflation/deflation procedure, and wherein the inflatable packer is a self-anchoring packer; and the fracture placement packer assembly is structured to be couplable to a conveyance device.

Description

BACKGROUND

The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.

The technical field generally, but not exclusively, relates to completing multiple fracturing stages in a wellbore. Presently known multi-stage fracturing techniques include a “plug and perf” operation (e.g. using bridge plugs between stages) and using an open hole packer with sliding sleeves. Presently known multi-stage fracturing techniques suffer from one or more drawbacks, with examples including: difficulty in controlling fracture placement; long cycle times between stages, e.g. to run tools into the hole; limitations on treatment execution such as the order of treating several intervals of a subterranean formation successively; and/or low reliability systems with intricate moving mechanical parts.

SUMMARY

In some embodiments, there are provided methods, comprising positioning a fracture placement packer assembly, comprising an inflatable packer positioned on an uphole side of the assembly, in a wellbore at a fracture treatment position; inflating the inflatable packer; fracture treating an interval of a subtteranean formation operationally coupled to the wellbore; and the methods further comprising at least one operation selected from the operations consisting of: marking the interval before the fracture treating; wherein the inflating the packer further comprises inflating a self-anchoring packer; fracture treating a second interval after the first interval, wherein the second interval comprises a greater measured depth than the first interval; fracture treating a second interval after the first interval, wherein the second interval comprises a smaller measured depth than the first interval, the method further including positioning a sand plug across the first interval before the fracture treating the second interval; fracture treating a second interval after the first interval, wherein the second interval comprises a smaller measured depth than the first interval, the method further including positioning a sand plug across the first interval before the fracture treating the second interval, wherein the sand plug comprises a high particulate fraction fluid having a plurality of particle size modalities therein; fracture treating a second interval after the first interval, wherein the second interval comprises a smaller measured depth than the first interval, the method further including positioning a sand plug across the first interval before the fracture treating the second interval, wherein the sand plug comprises a high particulate fraction fluid having a plurality of particle size modalities therein, and removing an amount of water from the sand plug; performing the fracture treating with a drill string positioned in the wellbore; performing the fracture treating with an uncemented casing string positioned in the wellbore; interpreting at least one of pressure information, temperature information, and inflation information, determining a wear value for the assembly in response to the information, and providing the wear value to an output device; wherein the marking comprises oriented marking; wherein the marking comprises a selected geometric configuration; wherein the marking comprises at least one operation selected from scoring, punching, perforating, pre-inflating the packer, gouging, grooving, and indenting; wherein the inflating comprises an operation selected from the operations consisting of providing a pressure pulse, dropping a ball, and providing an electrical signal; providing a liner in the wellbore, positioning a number of external packers between the liner and a wellbore face, wherein each of the external packers comprises an activatable packer, activating the external packers, and wherein the inflating the inflatable packer comprises running the inflatable packer to a selected position within the liner before the inflating; the method having the “providing a liner” operation, wherein the selected position comprises a position aligning the inflatable packer with one of the external packers; and the method having the “providing a liner” operation, wherein the activating the external packers comprises at least one operation selected from inflating the external packers, swelling the external packers, and mechanically activating the external packers.

Embodiments relate to systems, comprising: a fracture placement packer assembly comprising an inflatable packer positioned on an uphole side of the assembly; wherein the inflatable packer is structured to execute repeated inflation/deflation cycles in response to an inflation/deflation procedure, and wherein the inflatable packer is a self-anchoring packer; and wherein the fracture placement packer assembly is structured to be couplable to a conveyance device.

Embodiments aim at systems, comprising: a straddle packer assembly comprising a first inflatable packer positioned on an uphole side of the assembly and a second inflatable packer positioned on a down hole side of the assembly; wherein each of the inflatable packers are structured to execute repeated inflation/deflation cycles in response to an inflation/deflation procedure; wherein the fracture placement packer assembly is structured to be couplable to a conveyance device; and wherein the straddle packer assembly comprises a spacer element positioned between the first and second inflatable packers, the spacer element including a fluid conductance feature and the spacer element structured to maintain the inflatable packers at a specified distance.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 shows a straddle packer assembly with multiple inflatable packers.

FIG. 2 shows a positioned assembly in a wellbore.

FIG. 3 shows operations to fracture multiple zones using straddle packers.

FIG. 4 shows open hole completion systems using a packer.

FIG. 5 shows a straddle packer assembly operating in a wellbore having a cemented casing therein.

FIG. 6 shows a straddle packer assembly operating in a wellbore having an uncemented liner positioned therein across an interval of interest.

FIG. 7A illustrates a particle pack from the prior art.

FIG. 7B is a magnification of the pack illustrated in 7A.

FIG. 8A illustrates a particle pack as in the present disclosure.

FIG. 8B is a magnification of the pack illustrated in 8A.

DETAILED DESCRIPTION OF SOME ILLUSTRATIVE EMBODIMENTS

For the purposes of promoting an understanding of the principles of the disclosure, reference will now be made to the embodiments illustrated in the drawings and specific language will be used to describe the same. It will nevertheless be understood that no limitation of the scope of the claimed subject matter is thereby intended, any alterations and further modifications in the illustrated embodiments, and any further applications of the principles of the application as illustrated therein as would normally occur to one skilled in the art to which the disclosure relates are contemplated herein.

At the outset, it should be noted that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developer's specific goals, such as compliance with system related and business related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. In addition, the composition used/disclosed herein can also comprise some components other than those cited. In the summary and this detailed description, each numerical value should be read once as modified by the term “about” (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context. Also, in the summary and this detailed description, it should be understood that a concentration range listed or described as being useful, suitable, or the like, is intended that any and every concentration within the range, including the end points, is to be considered as having been stated. For example, “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10. Thus, even if specific data points within the range, or even no data points within the range, are explicitly identified or refer to only a few specific, it is to be understood that the Applicant appreciate and understands that any and all data points within the range are to be considered to have been specified, and that the Applicant possessed knowledge of the entire range and all points within the range.

Referencing FIG. 1, a straddle packer assembly 100 includes a first inflatable packer 102 positioned on an uphole side of the assembly 100, and a second inflatable packer 104 positioned on a downhole side of the assembly. Uphole and downhole, as utilized herein, refer to the measured depth of the wellbore, or to the intended orientation of the assembly 100, for example when assembled at a surface location and not in a wellbore. Uphole is the side at a smaller measured depth, or closer to the wellhead, and down hole is the side at a greater measured depth, or further from the wellhead.

In embodiments, the assembly 100 further includes each of the inflatable packers able to repeatedly execute an inflation/deflation cycle. The mechanics of the inflatable packers may be of any type, for example inflated or deflated by pressurized fluid pumped into the wellbore according to the positions of one or more sleeves, sliding elements, control valves, etc. The actuation of any moving parts of the inflatable packers may be electrical, pressure pulse activated, mechanical, actuated by a dropped ball pumped through a receiving device, or by any other actuation method. The specific operations of the inflatable packers are not limiting and are not further described herein.

The number of inflation/deflation cycles that is sufficient to be able to be repeatedly executed is dependent upon the specific application and will be known to one of skill in the art having the benefit of the disclosures herein. Certain numbers of operational cycles that meet the repeatedly executed criterion include, without limitation, include at least enough inflation/deflation cycles to complete two fracture treatments within a wellbore; at least enough inflation/deflation cycles to complete a nominal number of fracture treatments within a wellbore; at least enough inflation/deflation cycles to complete all contemplated fracture treatments within a wellbore; at least enough inflation/deflation cycles to complete a nominal number of fracture treatments for a specified number of wellbores; at least enough inflation/deflation cycles to complete all contemplated fracture treatments within a specified number of wellbores; and at least enough inflation/deflation cycles to provide an operating service life of the inflatable packers to provide an acceptable return on investment of the cost of the inflatable packers.

In embodiments, the assembly 100 further includes a spacer element 106 positioned between the packers 102, 104. The spacer element 106 includes a fluid conductance feature 110, and the spacer element 106 maintains the inflatable packers 102, 104 at a specified distance. Example and non-limiting fluid conductance features 110 include holes, ports, gaps, slots, or other features in the spacer element 106 to allow flow of fracturing fluids therethrough. An example fluid conductance feature 110 includes ports that open in response to a sliding sleeve, providing a fluid conductance feature 110 that is selectively opened.

The specified distance 108 is any distance desired that encompasses the desired fracturing zone. Example and non-limiting distances include at least about 10 feet, between about 10 feet and 30 feet (e.g. a standard tubular length), between about 30 feet and 90 feet (e.g. between one and three standard tubular lengths), and/or any distance up to about 1,000 feet. A short fracturing zone allows for precise placement of the fracturing treatment, but can run some risk of the fracture growing past one of the inflatable packers 102, 104 within the wellbore, which could run the risk of causing the assembly 100 to get stuck. Also, a short fracturing zone requires a greater number of fracturing treatments to stimulate a longer formation segment.

A long fracturing zone causes greater uncertainty in the placement of the fracturing treatment, can require high pumping rates for an acceptable fracture placement and geometry, and can induce multiple simultaneous fractures to occur (which may be a desired or undesired response). However, a long fracturing zone allows for the stimulation of a longer formation segment with fewer treatments. The long fracturing zone may also reduce the risk of a fracture growing past one of the inflatable packers 102, 104, depending upon the nature of the formation and the stress and natural fracturing profile therein. It is a mechanical step for one of skill in the art, having the benefit of the disclosures herein and contemplating information that is generally available for a particular formation, treating fluids available, and treating equipment available, to select a specified distance value for a particular application of the assembly 100.

In some embodiments, the assembly 100 is couplable to a conveyance device 112, and in the example of FIG. 1 is depicted as coupled to the conveyance device 112. Example and non-limiting conveyance devices 112 include a coiled tubing unit, a wellbore tubular, a wellbore casing, and/or a drill string. In certain embodiments, the spacer element 106 is included as a portion of the conveyance device 112, and/or as a modified portion of the conveyance device 112. For example, the spacer element 106 may be included as a modified tubular in a tubing string.

In certain embodiments, a system including the assembly 100 includes a wellbore marking tool. The wellbore marking tool is a tool structured to mark a fracture entry position of the wellbore, and can include any aspect of the wellbore, including at least a formation face 204 (e.g. see FIG. 2), a casing wall (cemented or uncemented), and/or a liner wall. The marking of the fracture entry position includes perforating, punching, scraping, scoring, grooving, and/or indenting the fracture entry position. Example and non-limiting wellbore marking tools include a rotary tool, a star shaped rotary tool, a scraping device, a fluid jetting device, an abrasive jetting device, a punching device, and/or any other device that is capable of marking the wellbore to provide for a preferential fluid entry or pressure failure point in the wellbore such that the fracture treatment is more likely to initiate at the marked position.

In certain embodiments, the wellbore marking tool is an oriented tool in the wellbore, such that the provided marks are oriented in a selected manner. An example orientation includes an orientation selected to reduce tortuosity of the fracture entry from the wellbore zone into the formation zone. The orientation may be azimuthal (e.g. azimuth of the plane perpendicular to the wellbore), for example when the wellbore is inclined relative to the formation (due to incline of the wellbore, the formation, or both). Additionally or alternatively, the orientation may be axial (e.g. a mark on one side of a wellbore is at a differential measured depth from an opposing mark on the other side of the wellbore), for example when the wellbore is angled on the horizontal plane at an offset from the highest in-situ stress. The provided examples of orienting the wellbore marking tool are non-limiting.

Referencing FIG. 2, a positioned assembly 200 is depicted in a wellbore at a formation of interest 202, which may comprise one or more intervals of interest. The wellbore segment depicted is horizontal in the example, although the wellbore may be vertical, deviated, highly deviated, or horizontal. The assembly is positioned within an uncemented liner 208. A number of external packers 206 are provided outside the liner 208, which may center the liner 208, prevent movement of the liner 208 during treatment operations, and/or provide zonal isolation of the interval 202 during treatment operations. The external packers 206 may be of any type, including at least inflatable packers, swellable packers, and/or mechanically operated packers. The first inflatable packer 102 is positioned at one of the external packers 206, and the second inflatable packer 104 is positioned at a second one of the external packers 206.

The positioning of the inflatable packers 102, 104 at the locations of the external packers 206 provides for more positive zonal isolation, and provides for a better stress profile for the liner when all packers and engaged and during treatment operations. However, the positioning of the inflatable packers 102, 104 at the locations of the external packers 206 is optional and non-limiting. The liner 208 may include ports, gaps, holes, or other features to allow passage of fracturing fluid therethrough. Additionally or alternatively, a wellbore marking tool may be utilized on the liner 208 to provide fluid passages therethrough or to provide a failure zone that will open upon during fracturing treatment operations.

Referencing FIG. 3, an operation to fracture multiple zones is depicted schematically. The operation 300 includes operating a star wheel mechanical punch throughout a wellbore zone to be treated. The wellbore depicted in FIG. 3 is an open hole completion. The operation 302 illustrates a straddle packer assembly being utilized to treat the wellbore in a toe-to-heel operation, fracturing zones from a higher measured depth value to a lower measured depth value. The operation 304 illustrates the straddle packer assembly being utilized to treat the wellbore in a heel-to-toe operation, fracturing zones from a lower measured depth value to a higher measured depth value. The wellbore may be fractured in any order, as the straddle packer assembly provides for zonal isolation wherever positioned.

The wellbore depicted in FIG. 4 is an open hole completion. The operation 400 includes operating a star wheel mechanical punch throughout a wellbore zone to be treated. The operation 402 illustrates a fracture placement packer assembly being utilized to treat the wellbore in a toe-to-heel operation. The fracture placement packer assembly includes an inflatable packer positioned on an uphole side of the assembly. The inflatable packer is designed to execute repeated inflation/deflation cycles. Unlike the opposing inflatable packers of the straddle packer assembly, the fracturing pressure provides a net uphole force onto the conveyance device and the fracture placement packer assembly. Accordingly, in certain embodiments, the inflatable packer of the fracture placement packer assembly is a self-anchoring packer. In certain embodiments, the inflatable packer of the fracture placement packer assembly is not a self-anchoring packer. In certain embodiments, one or more inflatable packers of the straddle packer assembly are self-anchoring packers.

In the example of FIG. 4, zonal isolation is provided after each fracture treatment by positioning a “sand plug”, which may be provided by utilizing any particulate laden fluid, across the previously treated interval, and the fracture placement packer assembly is positioned at a place to treat the next zone of the interval (or the next interval). Particulate laden fluids allow settling of the particles therein over time. In a vertical well, zone isolation can nevertheless be provided by adding enough fluid to account for settling. In a horizontal well, the settling occurs along the length of the isolated zone, and additional fluid will not assist in providing coverage for the settled areas. Additionally, a fluid loaded with a particulate material, such as a proppant, has a maximal packed volume fraction that provides for a maximum pressure drop through a pack of the fluid, even after settling. Again, in a vertical well, this is not a major limitation because the isolated zones below a treated zone, in addition to having a particle pack thereacross, are also generally at a higher fracturing stress than vertically higher zones that are being treated, which assists in providing zonal isolation. In a horizontal well, by contrast, an isolated zone is typically at the same or very similar fracturing stress to the next treated zone, and additionally already has induced fractures therein providing for a reduced initiating stress. Accordingly, providing zonal isolation with a “sand plug” or particle pack is more challenging in a horizontal or highly deviated wellbore.

Referencing FIG. 7, a previously known particle pack is provided for zonal isolation in a particular well segment. The particle pack is settled, providing for a head space 702 in the wellbore which will have a reduced isolation effectiveness. Additionally, in the expanded section 704, it can be seen that natural void spaces are provided through the particle pack, due to the natural packed volume fraction of the particles. The more uniform the particle sizes the lower the natural packed volume fraction of the particles and the greater the void spaces within the pack. A high degree of particle size uniformity is desirable for proppant materials utilized in fracturing treatments, which are therefore the typically available materials for a particle pack placement.

Referencing FIG. 8, a particle pack consistent with the present disclosure is depicted. The particle pack of FIG. 8 includes a number of particle size modalities 802, 804, including at least two particle size modalities, although three, four, five, or more particle size modalities are possible. Particle packs including multiple size modalities can have much higher packed volume fractions than single-sized materials, including packed volume fractions exceeding 75%, 80%, 85%, 90% and even exceeding 95% while still maintaining a fluidized material that can be pumped. Accordingly, head space from settled fluids are much lower in a fluid having two or more size modality particles. Further, the settling rate of fluids having two or more size modalities are much lower than single particle size fluids. In a single particle size fluid, the settling rate is largely defined by the fluid viscosity and the densities of the fluid and particles. While other characteristics, such as the viscoelastic nature of a fluid, can reduce settling rates, a single particle size fluid in a completely static particle pack will nevertheless settle out the particles in a short period of time. Fluids having high concentrations of two or more size modality particles can avoid particle settling for hours or days, even with very low carrier fluid viscosities. Accordingly, the particle pack of FIG. 8 has very little settling, and a much lower head space even after settling occurs.

Particle packs created from fluids having two or more size modality particles can re-fluidize with a very small amount of liquid. This can be a desirable feature, for example when cleaning out the particle packs and returning a well to production. However, during zonal isolation the re-fluidization of the particle pack may be undesirable. In certain embodiments, the particle pack is provided as a fluid having two or more size modality particles and further including a water removal constituent. Example and non-limiting water removal constituents include fibers (which may be hydroscopic, or may just provide support from particle movement occurring, similar to a proppant fracture flowback prevention material), a hydroscopic material, and/or a water absorbent material (e.g. bentonite, a polymer, etc.). Example and non-limiting materials include coated materials, for example a material that is not active to absorb water until placed across the zone to be isolated, and in response to time, temperature, pressure, and/or a reaction the coating is removed and water absorption or other removal commences. Additionally or alternatively, the water removal and/or particle pack fixing material (e.g. fibers) will degrade at a later time, allowing the particle pack to re-fluidize and enhance cleanup.

Referencing FIG. 5, a straddle packer assembly is depicted operating in a wellbore having a cemented casing therein. A mechanical marking tool such as a star-wheel punch is run through the zones of interest in operation 500, puncturing the casing, and potentially scoring the cement. The straddle packer assembly is utilized in operation 502 to fracture an interval of the formation of interest from toe-to-heel, in operation 504 to fracture an interval of the formation from heel-to-toe, or otherwise utilized to fracture an interval the formation in any selected manner.

Referencing FIG. 6, a straddle packer assembly is depicted operating in a wellbore having an uncemented liner positioned therein across an interval of interest. The liner is punched, scored, or perforated, although it also may not be, and the straddle packer assembly fractures the interval of interest from toe-to-heel in operation 600, or fractures the interval of interest from heel-to-toe in operation 602. The inflatable packers of the straddle packer assembly are aligned with external packers in the illustration of FIG. 6, although in certain embodiments the external packers may not be present or may not be aligned with the inflatable packers of the straddle packer assembly.

The schematic flow descriptions which follow provide illustrative embodiments of performing procedures for multi-stage completions in a wellbore. Operations illustrated are understood to be examples only, and operations may be combined or divided, and added or removed, as well as re-ordered in whole or part, unless stated explicitly to the contrary herein. Certain operations illustrated may be implemented by a computer executing a computer program product on a computer readable medium, where the computer program product comprises instructions causing the computer to execute one or more of the operations, or to issue commands to other devices to execute one or more of the operations.

Certain operations described herein include operations to interpret one or more parameters. Interpreting, as utilized herein, includes receiving values by any method known in the art, including at least receiving values from a datalink or network communication, receiving an electronic signal (e.g. a voltage, frequency, current, or PWM signal) indicative of the value, receiving a software parameter indicative of the value, reading the value from a memory location on a computer readable medium, receiving the value as a run-time parameter by any means known in the art including operator entry, and/or by receiving a value by which the interpreted parameter can be calculated, and/or by referencing a default value that is interpreted to be the parameter value.

An example procedure includes an operation to position a fracture placement packer assembly, including an inflatable packer positioned on an uphole side of the assembly, in a wellbore at a fracture treatment position. The procedure includes an operation to inflate the inflatable packer, and to fracture treat an interval of a formation operationally coupled to the wellbore. In certain embodiments, the procedure includes an operation to mark the interval before the fracture treating, and/or to inflate the packer by inflating a self-anchoring packer. In certain embodiments, the procedure includes an operation to fracture treat a second interval after the fracturing of the first interval, where the second interval is at a greater measured depth than the first interval.

In certain embodiments, the procedure includes an operation to fracture treat a second interval after the fracturing of the first interval, where the second interval is at a smaller measured depth than the first interval, and an operation to position a particle pack or sand plug across the first interval before the fracture treating the second interval. An example procedure further includes an operation to position the particle pack across the first interval by positioning a high particulate fraction fluid, having a number of particle size modalities in the fluid, across the first interval. Certain further embodiments of the procedure include fixing the particle pack in place (e.g. with fibers), and/or removing an amount of liquid fluid (e.g. water) from the particle pack. An example operation to remove an amount of liquid fluid from the particle pack includes placing a water removal constituent in the high particulate fraction fluid.

In certain embodiments, the procedure includes an operation to fracture treat an interval of a formation with a drill string positioned in the wellbore, and/or to perform the fracture treatment with an uncemented casing string (and/or a liner) positioned in the wellbore. In certain embodiments, the procedure includes an operation to provide a liner in the wellbore, to position a number of external packers between the liner and a wellbore face, where each of the external packers includes an activatable packer, an operation to activate the external packers, and where the operation to inflate the inflatable packer includes running the inflatable packer to a selected position within the liner before the inflating. In certain embodiments, the selected position is a position aligning the inflatable packer with an external packer. In certain embodiments, the operation to activate the external packers includes inflating the external packers, swelling the external packers, and/or mechanically activating the external packers.

In certain embodiments, the procedure includes an operation to interpret pressure information, temperature information, and/or inflation information, and to determine a wear value for the assembly in response to the information. The determining the wear value may be according to assembly wear modeling, experience in similar operational settings, and/or according to manufacturer wear information. The procedure further includes an operation to provide the wear value to an output device, for example a monitoring screen, a report, a maintenance system, a datalink or network, and/or to store the value on a computer readable medium in non-transitory memory.

In certain embodiments, the marking operation includes an oriented marking operation and/or a marking operation including a selected geometric configuration (e.g. 3 marks at 120° intervals, 6 marks at 60° intervals, etc.). In certain embodiments, the marking operation includes scoring, punching, perforating, pre-inflating the packer, gouging, grooving, and/or indenting a wellbore surface such as a casing, cement layer, liner, and/or formation face. In certain embodiments, the inflating operation includes providing a pressure pulse, dropping a ball, providing pick-up, set-down, or rotational force to a tubular, providing an electrical signal, and/or pumping a fluid into a wellbore and/or tubular.

As is evident from the figures and text presented above, a variety of embodiments according to the present disclosure are contemplated.

EXAMPLES

Example 1

Inflatable Straddle Packers in Barefoot Openhole

The horizontal portion of the wellbore is completely barefoot, with no liner in the wellbore. The rock or formation face may be marked by a device to reduce the hoop stress and bias the fracture initiation location. Marking the rock face means creating some mechanical defect such as a gouge, perforation, groove, indentation etc. For example, a star shaped rotary tool may be pulled along the entire length of the horizontal lateral in a manner that leaves a continuous line of indentations into the rock face. Another means of marking the rock face is to over inflate the packer.

An inflatable straddle packer system can be run into the hole on coiled tubing, or jointed pipe after removing the rock face marking device. The inflatable straddle packer system can be spaced apart by any length of tubing as desired. Frac ports or openings in the tubing between the two inflatable packers will allow the injected fracturing fluid to exit the treatment line fill the isolated portion of the wellbore between the straddle packers and induce fractures once it reaches the appropriate fracturing pressure. The inflatable packers will have some control valve that will be activated by a downhole action (pressure pulse, ball drop, electrical signal from battery) to either initiate an inflation sequence or a deflation sequence. FIG. 3 illustrates this multi-staging example.

The fracturing fluid injection operation can begin once the packers are inflated and the desired portion of the horizontal wellbore is isolated. Two opposing inflatable packers should be self anchoring during fluid injection into the formation between the two packers. Packer anchor force can be adjusted as desired. In some embodiments, the opposing packers exert similar force on the connecting tubing albeit in the opposite direction.

An advantage of the straddle packer system is that one may create fractures at any arbitrary point along the horizontal wellbore in any order desired. Toe-to-heel, heel-to-toe, or even alternating toe, heel, middle, near-toe, near-heel, etc. is possible simply by controlling packer inflation, deflation, and pulling the conveyance tubing in or out of hole to position the straddle packers at the desired depth.

In some embodiments, a single packer does not have a balanced force offered by the opposing straddle, and is designed to be self-anchoring. In some embodiments, a single packer has some alternative means of isolating below the packer. A sand plug in the wellbore is one possible means to achieve this result. A conditioned sand (such as fibers or a hydroscopic water absorbent material) may also be able to accommodate this. A multimodal slurry may be particularly effective because the particles will not settle and create a headspace in the horizontal wellbore that compromises zonal isolation. Moreover, adding a material such as fibers, or a hydroscopic, or water absorbent material to Mosaic will make the subsequent bridge less fluid and thus less able to reopen the previously created fracture. This example is depicted in FIG. 4.

The inflatable packer and control valve system described in this scenario can enable Fracture While Drilling (FWD) and Fracture While Casing (FWC).

Example 2

Inflatable Straddle Packers in a Perforated Cemented Liner

In this example, the horizontal portion of the wellbore is cased and cemented. The casing can be perforated mechanically after cementing by some device to bias the fracture initiation location. Perforating the casing means creating certain holes such as a gouge, perforation, groove, indentation etc. that extends through the casing, but not necessarily through the cement. For example, a star shaped rotary tool may be pulled along the entire length of the horizontal lateral in a manner that leaves a continuous line of indentations through the casing.

An inflatable straddle packer system can be run into the hole on coiled tubing, drill pipe, production tubing, or casing after removing the rockface marking device. The inflatable packer system could provide a platform for the mechanical perforator. The inflatable packer affords considerable forces to the casing and if accompanied with a decent toolkit, could perform that function. FIG. 5 illustrates this multi-staging example.

The treatment sequence can be operated similarly as described in Example 1 above.

Example 3

Inflatable Straddle Packers in Uncemented Liner with External Inflatable Casing Packers

This example proposes an improvement on the state-of-the-art uncemented liner systems that are in commercial use today. The commercial systems may include mechanical packers (RockSeal) and swellable packers. As a consequence of being installed in the low side of the horizontal wellbore, the existing commercial systems are not particularly well suited for effective isolation toward the high side. Most service providers test the products “on-center” and extrapolate results for off-center use. Part of the theory of operation is that the packer forms an acceptable barrier albeit not completely pressure tight. In a fracturing operation, sand that is in transport across the packer is dehydrated and forms a bridge affecting a good-enough seal. The good-enough seal is one that substantially contains most of the volume of frac fluid so a frac can be placed effectively. This is recognized (and accepted) by the operators because after all, it is better than no isolation at all and it serves the purpose to build the frac.

The use of an inflatable packer may assure good contact everywhere on the rockface. Moreover, the contact provides good contact pressure necessary to form a competent seal. This is further assured because during the inflation process, the packer may lift the liner to the center of the wellbore, as the hydroforming forces are considerable. The packer can be manufactured in lengths suitable for assurance of good zonal isolation.

The advantages to this approach are that the customer can be assured of isolation during stimulation treatment and have a better confidence achieving the treatment design. Further, it can provide zonal isolation during the productive life of the well. Selective frac sleeves may also be used in the productive phase. The inflation valve for this system is much straightforward.

Additionally, the following passage details how an inflatable openhole zonal isolation system can be used effectively with inflatable packers to achieve rapid multistage fracturing operations. It is recommended that the rockface be marked by some device to reduce the hoop stress and bias the fracture initiation location before the liner is run in the hole. Marking the rockface means creating some mechanical defect such as a gouge, perforation, groove, indentation etc. For example, a star shaped rotary tool may be pulled along the entire length of the horizontal lateral in a manner that leaves a continuous line of indentations into the rockface.

The liner will have two additional features. One feature is a number of external inflatable packer elements whose purpose is to create a seal between the liner basepipe and the rockface. Long inflatable elements or multiple adjacent packers (virtually without space between the end of each packer element) may be installed to reduce the likelihood of a longitudinal fracture from communicating from one isolated zone of the wellbore to another. The individual or clusters of inflatable packer elements will be spaced apart by any distance desired, thus creating a series of isolated wellbore segments. One can imagine each segment between packers to be at least 10 feet and probably less than 1000 feet. A second feature is that the liner may have either pre-formed holes (slots, holes, etc) or sliding sleeves between each of the spaced inflatable packer elements. These holes/sliding sleeves will permit injected hydraulic fracturing fluid to exit the interior of the liner, fill the space between the liner and the rockface and create hydraulic fractures at sufficient injection pressure. Sliding sleeves can be open and closed by the normal means (control lines, ball drop, shifting tool). All the inflatable packer elements will be inflated to create isolated zones along the horizontal wellbore after installation of the liner.

An inflatable straddle packer system can be run into the hole on coiled tubing, drill pipe, production tubing, or casing after inflating the external liner inflatable packers. The inflatable straddle packer system can be spaced apart by whatever length of tubing is desired, but preferably, the straddle packers will align with the external liner packers to create a positive seal. If the liner basepipe is not continuously perforated, then the inflatable packers need only seat on unperforated basepipe straddling a sliding sleeve or predrilled hole. Frac ports or openings in the tubing between the two inflatable packers will allow the injected fracturing fluid to exit the treatment line fill the isolated portion of the liner, and subsequently the wellbore between the external liner packers and induce fractures once it reaches the appropriate fracturing pressure. The inflatable packers may have some control valve that will be activated by a downhole action (pressure pulse, ball drop, electrical signal from battery) to either initiate an inflation sequence or a deflation sequence.

The fracturing fluid injection operation can begin once the packers are inflated and the desired portion of the horizontal wellbore is isolated. Two opposing inflatable packers can be self-anchoring during fluid injection into the formation between the two packers. Packer anchor force can be applied as desired. The opposing packers may exert similar force on the connecting tubing albeit in the opposite direction. In some embodiment, a single packer is used which may be self-anchoring. FIG. 6 illustrates this multi-staging example.

A single packer may also be used with some alternative means of isolating below the packer. A sand plug in the wellbore is one means of doing this. The multimodal slurry may be particularly effective because the particles will not settle and create a headspace in the horizontal wellbore that compromises zonal isolation. Moreover, adding a material such as fibers, or a hydroscopic, or water absorbent material to Mosaic will make the subsequent bridge less fluid and thus less able to reopen the previously created fracture.

While the disclosure has provided specific and detailed descriptions to various embodiments, the same is to be considered as illustrative and not restrictive in character. Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this disclosure. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures.

Moreover, in reading the claims, it is intended that when words such as “a,” “an,” “at least one,” or “at least one portion” are used there is no intention to limit the claim to only one item unless specifically stated to the contrary in the claim. When the language “at least a portion” and/or “a portion” is used the item can include a portion and/or the entire item unless specifically stated to the contrary. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Claims

1. A method, comprising:

positioning a fracture placement packer assembly, comprising an inflatable packer positioned on an uphole side of the assembly, in a wellbore at a fracture treatment position;

inflating the inflatable packer;

fracture treating an interval of a subtteranean formation operationally coupled to the wellbore; and

the method further comprising at least one operation selected from the operations consisting of: marking the interval before the fracture treating; wherein the inflating the packer further comprises inflating a self-anchoring packer; fracture treating a second interval after the first interval, wherein the second interval comprises a greater measured depth than the first interval; fracture treating a second interval after the first interval, wherein the second interval comprises a smaller measured depth than the first interval, the method further including positioning a sand plug across the first interval before the fracture treating the second interval; fracture treating a second interval after the first interval, wherein the second interval comprises a smaller measured depth than the first interval, the method further including positioning a sand plug across the first interval before the fracture treating the second interval, wherein the sand plug comprises a high particulate fraction fluid having a plurality of particle size modalities therein; fracture treating a second interval after the first interval, wherein the second interval comprises a smaller measured depth than the first interval, the method further including positioning a sand plug across the first interval before the fracture treating the second interval, wherein the sand plug comprises a high particulate fraction fluid having a plurality of particle size modalities therein, and removing an amount of water from the sand plug; performing the fracture treating with a drill string positioned in the wellbore; performing the fracture treating with an uncemented casing string positioned in the wellbore; interpreting at least one of pressure information, temperature information, and inflation information, determining a wear value for the assembly in response to the information, and providing the wear value to an output device; wherein the marking comprises oriented marking; wherein the marking comprises a selected geometric configuration; wherein the marking comprises at least one operation selected from scoring, punching, perforating, pre-inflating the packer, gouging, grooving, and indenting; wherein the inflating comprises an operation selected from the operations consisting of providing a pressure pulse, dropping a ball, and providing an electrical signal; providing a liner in the wellbore, positioning a number of external packers between the liner and a wellbore face, wherein each of the external packers comprises an activatable packer, activating the external packers, and wherein the inflating the inflatable packer comprises running the inflatable packer to a selected position within the liner before the inflating; the method having the “providing a liner” operation, wherein the selected position comprises a position aligning the inflatable packer with one of the external packers; and the method having the “providing a liner” operation, wherein the activating the external packers comprises at least one operation selected from inflating the external packers, swelling the external packers, and mechanically activating the external packers.

2. A system, comprising:

a fracture placement packer assembly comprising an inflatable packer positioned on an uphole side of the assembly;

wherein the inflatable packer is structured to execute repeated inflation/deflation cycles in response to an inflation/deflation procedure, and wherein the inflatable packer is a self-anchoring packer; and

wherein the fracture placement packer assembly is structured to be couplable to a conveyance device.

3. The system of claim 2, wherein the conveyance device comprises a device selected from the devices consisting of: a coiled tubing unit, a wellbore tubular; a wellbore casing; and a drill string.

4. The system of claim 2, wherein the inflation/deflation procedure is performed using a device selected from the devices consisting of: a pressure pulse generator; an electrical signal generator; and ball activated actuator.

5. The system claim 2, further comprising a wellbore having a first interval and a second interval, the second interval at a smaller measured depth than the first interval, the fracture placement packer assembly positioned at a smaller measured depth than the second interval, the system further comprising a deviation device positioned across the first interval.

6. The system of claim 5, wherein the wellbore at the position of the first interval is one of horizontal and highly deviated, and wherein the deviation device comprises a sand plug.

7. The system of claim 6, wherein the sand plug comprises a high particulate fraction fluid having a plurality of particle size modalities therein.

8. The system of claim 7, wherein the high particulate fraction fluid further comprises a water removal constituent.

9. The system of claim 8, wherein the water removal constituent comprises a material selected from the materials consisting of: fibers, a hydroscopic material, a water absorbent material, and a coated material.

10. The system of claim 2, further comprising a wellbore marking tool.

11. The system of claim 10, wherein the wellbore marking tool comprises a tool selected from the tools consisting of a scoring device, a punching device, a cladding coupled to the inflatable packer, a gouging device, a grooving device, an indentation device, a rotary tool, and a star shaped rotary tool.

12. A system, comprising:

a straddle packer assembly comprising a first inflatable packer positioned on an uphole side of the assembly and a second inflatable packer positioned on a down hole side of the assembly;

wherein each of the inflatable packers are structured to execute repeated inflation/deflation cycles in response to an inflation/deflation procedure;

wherein the fracture placement packer assembly is structured to be couplable to a conveyance device; and

wherein the straddle packer assembly comprises a spacer element positioned between the first and second inflatable packers, the spacer element including a fluid conductance feature and the spacer element structured to maintain the inflatable packers at a specified distance.

13. The system of claim 12, wherein the conveyance device comprises a device selected from the devices consisting of: a coiled tubing unit, a wellbore tubular; a wellbore casing; and a drill string.

14. The system of claim 12, wherein the inflation/deflation procedure is performed using a device selected from the devices consisting of: a pressure pulse generator; an electrical signal generator; and ball activated actuator.

15. The system of claim 12, further comprising a wellbore marking tool.

16. The system of claim 15, wherein the wellbore marking tool comprises a tool selected from the tools consisting of a scoring device, a punching device, a cladding coupled to at least one of the inflatable packers, a gouging device, a grooving device, an indentation device, a rotary tool, and a star shaped rotary tool.

17. The system of claim 12, further comprising a liner positioned across a target fracturing zone, and wherein the straddle packer assembly is positioned such that the first and second inflatable packers define the target fracturing zone.

18. The system of claim 17, wherein the liner is not cemented, the system further comprising two external packers positioned between a formation face comprising the target fracturing zone, and wherein the first and second inflatable packers are each positioned at one of the two external packers.

19. The system of claim 18, wherein the two external packers comprise one of inflatable packers, swellable packers, and mechanically activated packers.

20. The system of claim 12, wherein the fluid conductance feature comprises at least one feature selected from the features consisting of: slots, ports, openings, and a sliding sleeve.

21. The system of claim 12, wherein the specified distance comprises a distance selected from the distance ranges consisting of: five feet to ten feet, inclusive; ten feet to thirty feet, inclusive; thirty feet to ninety feet, inclusive; and ninety feet to one thousand feet, inclusive.