Methods for Unconventional Gas Reservoir Stimulation With Stress Unloading For Enhancing Fracture Network Connectivity

Abstract

The invention discloses a method for use in a wellbore in a tight gas shale formation, comprising: providing a hydraulic fracturing fluid to initiate at least a fracture in the shale; injecting a treatment fluid in the fracture to at least partially destabilize and remove the shale; and repeating the step of fracturing the shale.

Description

FIELD OF THE INVENTION

This invention relates generally to method for treating a well penetrating a subterranean formation. More specifically, the invention relates to a method of hydraulic fracturing.

BACKGROUND

Some statements may merely provide background information related to the present disclosure and may not constitute prior art.

Various methods are known for fracturing a subterranean formation to enhance the production of fluids therefrom. In the typical application, a pressurized fracturing fluid hydraulically creates and propagates a fracture. The fracturing fluid carries proppant particulates into the extending fracture. When the fracturing fluid is removed, the fracture does not completely close from the loss of hydraulic pressure; instead, the fracture remains propped open by the packed proppant, allowing fluids to flow from the formation through the proppant pack to the production wellbore.

The success of the fracturing treatment may depend on the ability of fluids to flow from the formation through the proppant pack. In other words, the proppant pack or matrix must have a high permeability relative to the formation for fluid to flow with low resistance to the wellbore. Furthermore, the surface regions of the fracture should not be significantly damaged by the fracturing to retain fluid permeability for optimal flow from the formation into the fracture and the proppant pack.

Prior art have sought to increase the permeability of the proppant pack by increasing the porosity of the interstitial channels between adjacent proppant particles within the proppant matrix. For example, U.S. Pat. No. 7,255,169, U.S. Pat. No. 7,281,580, U.S. Pat. No. 7,571,767 discloses a method of forming a high porosity propped fracture with a slurry that includes a fracturing fluid, proppant particulates and a weighting agent. These prior art technologies seek to distribute the porosity and interstitial flow passages as uniformly as possible in the consolidated proppant matrix filling the fracture, and thus employ homogeneous proppant placement procedures to substantially uniformly distribute the proppant and non-proppant, porosity-inducing materials within the fracture. In another approach, proppant particulates and degradable material do not segregate before, during or after injection to help maintain uniformity within the proppant matrix. Fracturing fluids are thoroughly mixed to prevent any segregation of proppant and non-proppant particulates. In another approach, non-proppant materials have a size, shape and specific gravity similar to that of the proppant to maintain substantial uniformity within the mixture of particles in the fracturing fluid and within the resulting proppant pack. A tackifying compound coating on the particulates has also been used to enhance the homogenous distribution of proppant and non-proppant particulates as they are blended and pumped downhole into a fracture.

It is an object of the present invention to provide an improved method of fracturing.

SUMMARY

The current method is for use in a wellbore in a tight gas shale formation, and comprises: providing a hydraulic fracturing fluid to initiate at least a fracture in the shale; injecting a treatment fluid in the fracture to at least partially destabilize and remove the shale; and repeating the step of fracturing the shale.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 schematically illustrates in section placement of proppant and removable channelant in a hydraulic fracture operation according to one embodiment.

FIG. 2 schematically illustrates an initial fracture with two perforated intervals used for fluid circulation.

FIG. 3 schematically illustrates an initial fracture intersected by two wells used for fluid circulation.

FIG. 4 schematically illustrates according to one embodiment a final fracture after formation unloading in the near wellbore zone by circulating chemically active fluid followed by refracturing.

FIG. 5 schematically illustrates a wellbore connected to the tight gas shale reservoir resources through preexisting fractures (a). After unloading the reservoir rock near the initial fracture, refracturing and proppant replacement, the pre-existing fractures are open wider around the fracture part near the wellbore providing better connectivity to the reservoir matrix (b).

FIG. 6 shows schematics of fracture complexity levels.

FIG. 7 shows schematic of TGS circulating system for massive shale removal and formation unloading targeting the enhancement of pre-existing fracture network connectivity.

FIG. 8 shows gas release from coal beds versus pressure in comparison with gas production from tight sand formations.

FIG. 9 shows tectonic fractures and stratigraphic controls on cleats.

FIG. 10 shows hydraulic fracturing scenarios in coal bed versus the stress anisotropy and orientation: (a)—fracturing across face cleats, (b)—fracturing along face cleats, (c)—complex fracturing through both face and butt cleat systems with a single dominant fracture, (d)—complex fracturing with multiple dominant fractures.

DESCRIPTION

At the outset, it should be noted that in the development of any actual embodiments, numerous implementation-specific decisions must be made to achieve the developer's specific goals, such as compliance with system and business related constraints, which can 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.

The description and examples are presented solely for the purpose of illustrating embodiments of the invention and should not be construed as a limitation to the scope and applicability of the invention. In the summary of the invention 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 of the invention 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 inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that inventors possession of the entire range and all points within the range disclosed and enabled the entire range and all points within the range.

A new method for hydraulic fracturing (HF) of tight gas shale (TGS) is proposed in this document. Frequently, TGS such as the Barnett shale of north Texas has a low permeability fractured matrix with the gas mainly accumulated in the porous blocks but the large scale permeability provided primarily by the pre-existing fractures. For the Barnett Shale it has been reported by a geomechanics company that all of the natural fractures are either closed or mineralized. The conventional HF often does not result in the expected fractured well productivity. This happens, probably, because the created fractures, which are propped open with proppant, inevitably compress the surrounding reservoir rock closing partially or completely the pre-existing fractures as shown schematically in FIG. 1. When the pre-existing fractures are closed, the drainable reservoir volume, containing gas, suffers impaired connectivity with the wellbore. This hypothesis is supported by frequently reported observations that most likely, there is no correlation between the size or length of fractures created by HF and the resulting productivity of wellbore. In general, treatment volumes (both water and proppant) along with pump rates have increased due to favorable production response. It is also supported by the established industry trend to use Slick Water Frac or Water Frac technologies for tight gas shale stimulations with extremely small amount of proppant or send placed in created fractures. This approach allows for partial mitigating natural fracture network closure near created dominant fractures. The proposed completion methodology creates propped fractures and mitigates pre-existing fracture closure (compression) by unloading reservoir rock surrounding the created fracture. In this way the connectivity damage induced by the reservoir rock compression is overcome. The same approach should be equally applicable to the coalbed methane (CBM) well stimulation since the stress unloading is a compulsory requirement for the absorbed gas release from coal seams. Reservoir pressure decrease is required for the methane to desorb from the surface of the coal. While decreasing reservoir pressure will result in decreases effective stress, it is the pressure that effects methane desorbtion.

In FIG. 1, wellbore 10 is connected to the TGS reservoir 11 matrix through the preexisting fractures 12. The conventional HF leads to the compression of reservoir rock adjacent to the fracture and is accompanied by partial or complete closure of preexisting fractures almost everywhere except the near fracture tip zones (b and c). The preexisting fractures are closed inside the domain with a dashed boundary 13. The surfaces of the created fracture 12, which are connected to the matrix, are located near the fracture tips only; they are inside the domain with a dash boundary 14 at the top view (b) and between the curves 13 and 14 at the side view (c).

The proposed method disclosed herewith for HF of TGS involves the following steps and procedures:

• • 1. The creation of an initial fracture, probably, of reduced size or length filled with proppant pack using existing HF technology.
  • 2. The injection or circulation of a chemically active fluid through the initial hydraulic fracture, in order to discretely destabilize the reservoir rock surrounding it and to erode and remove the destabilized shale material from the fracture. This should result in unloading the surrounding formation of the stresses induced by HF.
  • 3. After stresses within the formation rock surrounding the initial fracture are unloaded, the HF is repeated in order to; a) remove or relocate the residual mixture of destabilized shale material and proppant further from the near wellbore producing region, b) replace the proppant near the wellbore, and c) to restabilize the shale by injecting a chemical treatment into the HF and pre-existing fracture network.
  • 4. After pressure relaxation following the completion method, production from the well can be initiated to cleanup the proppant pack placed inside the final fracture.

The essence of this method and its main differentiation from existing HF technology currently deployed on a regular basis in, Barnett shale gas completions is that the conceived method seeks the simultaneous creation of high permeability conduit (hydraulic fracture) connecting reservoir to the wellbore, while also unloading the additional induced reservoir rock stresses, in order to preserve the openness of pre-existing fractures. The above-outlined steps and procedures are discussed below in more detail.

Creation of Initial Fracture.

The purpose of the initial fracture is mainly to establish access to the reservoir rock, which will be containing the final propped hydraulic fracture, rather than to connect the wellbore with the reservoir drainage volume. For this reason, the initial fracture may not be too long. This fracture should also have at least two ports connecting it to the wellbore in order to provide an opportunity for simultaneous or alternate injection and production of chemically active fluid into and out of the fracture. A couple of ways to achieve this goal are shown schematically in FIG. 2 and FIG. 3.

Fluid Circulation Inside Initial Fracture.

The circulation of chemically active fluid within and across the fracture facies of the initial fracture is needed to destabilize a thin layer of the reservoir rock (i.e. shale) adjacent to the initial fracture and then to remove the residual destabilized material from the fracture. This should be easier to accomplish if the fracture width is wider and proppant particle size is larger. In order to expose the greatest possible area of the initial hydraulic fracture to the destabilizing treatment, the downhole injection and production ports should be configured for optimum sweep efficiency. The destabilization treatment could be implemented as fluid circulation (simultaneous injection and production) or by alternate injection and production cycles. A reversal of flow direction inside the fracture (back flushing) after a few circulation cycles may also help to achieve better fluid deployment within the initial fracture and prevent or minimize initial proppant pack plugging. The risk of proppant pack plugging by the residual material should not be underestimated, especially if the shale is excessively active with respect to the circulating treatment fluid. Process design & treatment validation experimentation will be required to establish fluid effectiveness, as well as robust and reliable fluid circulation procedures.

FIG. 2 shows an initial fracture with a single perforated interval used for fluid injection (a); two perforated intervals can be used for fluid circulation (b); different combinations of these two injection 25/circulation 26 schemes are also possible. A packer 21 and perforations 23 are used. The technique would be similar to the CBM cavitation technique where alternating injection and flowing the well are performed, however in CBM cavitation the wellbore and formation are highly overpressured so that the almost instantaneous pressure release creates a significant differential pressure which helps the coal to geomechanically fail. The coal reservoir is very overpressured to begin with which contributes to the success of this technique.

FIG. 3 shows an initial fracture intersected by two wells used for fluid circulation. There is evidence from microseismic monitoring and observation in adjacent producing wellbores that hydraulic fractures have communicated. It is not clear whether the communication is a result of intersecting hydraulic fractures or hydraulic fractures intersecting the actual adjacent wellbore. The approach to connect wellbores with a hydraulic fracture has been successfully performed in the past (late 1970's-early 1980's) as part of the hot dry rock program in the U.S. Vertical wells were drilled into geothermal reservoirs and then hydraulic fracturing treatments were performed on order to connect the wellbores. The intent was then to inject water into one wellbore, circulate fluid through the hydraulic fracture to heat the water, produce the water through another wellbore and used the heated water to generate electricity.

Chemistry of Circulating Fluid.

The primary functions of the initial injected and/or circulated treatment fluids are to:

• • 1. Create the initial hydraulic fracture,
  • 2. Place proppant to maintain the initial hydraulic fracture,
  • 3. Destabilize and disperse successive thin layers of reservoir rock (e.g. shale) adjacent to and along the face of the initial hydraulic fracture and
  • 4. Transport (sweep) the destabilized formation material from the initial hydraulic fracture.

Unlike the fluids deployed in conventional drilling & shale gas fracturing treatments, the fluids conceived for this methodology are designed specifically to de-stabilize the rock facies, within the reservoir and adjacent to the wellbore, promoting:

• • 1. Macroscopic mechanical failure,
  • 2. Resultant loose particulate degradation,
  • 3. Dispersion of the particulates into the fluid contained within and passing through the created fracture.

Additional key functions of the fluids to be deployed as a component of the conceived completion procedure are:

• • 1. Effective transport of the degraded formation particulates out of the initial fracture adjacent to the producing wellbore and
  • 2. Re-stabilization of the rock facies within the created and pre-existing fracture network exposed to the treatment fluid.

Reservoir rock formation composition and morphology will impact the specific chemistry that will be most effective for these treatment fluids. The specific mechanisms by which reservoir formation (especially shales) may be de-stabilized and dispersed as a result of treatment fluid contact are as follow:

• • 1. Inducing the swelling/expansion of in situ clays, within the rock matrix and/or resident fill material within micro-fractures, bedding planes or joints adjacent to the created hydraulic fracture.
  • 2. Dissolution of cementaceous materials present within formation matrix, fractures or joints.
  • 3. Dehydration of matrix or inter-granular binding (cementation) materials.
  • 4. Reduction of wellbore fluid pressure to equivalent or less than that of (shale) reservoir pressure.
  • 5. Inducing turbulent flow at the interface between the fluid in the fracture and the formation fracture face.
  • 6. A combination of any of the above.

By applying the antithesis of most drilling and completion fluid technologies it should be possible to produce and demonstrate effective formation destabilization treatments.

Examples of specific treatment chemistries and/or processes which could be embodied in this conceived completion procedure are as follows (Most likely the specific chemistry applied will be dependent upon the reservoir rock properties):

• • Prolonged or sequential injection/circulation of freshwater or brine.
  • Sequential injection/circulation of freshwater followed by highly saline fluids.
  • Circulation of oil based fluid (emulsion) containing freshwater as the emulsified phase.
  • Circulation of oil-based fluid (emulsion) containing highly saline fluid as the emulsified phase followed by circulation of freshwater.
  • Injection/circulation of aqueous fluids containing any of several polyphosphate compounds.
  • Injection/circulation of aqueous fluids containing any of several polymeric deflocculants, such as SSMA.
  • Injection/circulation of acidic fluids.
  • Injection/circulation of highly alkaline fluids.
  • Any of the above fluids containing added surfactant and/or dispersant.

Optimization of the treatments composition and design for most types of reservoir rock is possible. Treatment circulating time and rate (sequences) will be dependent upon formation rock reactivity, dispersed particulate size and initial proppant pack porosity and permeability.

Formation re-stabilization treatments may be required to prevent progressive formation deterioration after destabilization. Re-stabilization is likely to be essential to ensure that the proppant pack, following re-fracture treatment, remains unimpaired, free of formation fragments. Restabilization treatments will most likely involve circulation of a post-treatment fluid containing any of a number of products (such as polyamines) often referred to as “permanent shale inhibitors”.

Refracturing

The refracturing is needed for final cleanup of the initial fracture interior. Due to rock unloading, the fracture reopening should be easier to achieve than the creation of the initial fracture. Not being linking to a theory, it would be possible to mobilize the settled and, probably, plugged proppant bed. The proppant flow back phenomenon frequently observed in the field indicates that this is not impossible. How to enhance the mobilization of the proppant inside the initial fracture during refracturing has to be understood yet. The fracture size or length has to be extended during refracturing mainly to accommodate the mixture of mobilized proppant with the residual material. It will inevitably create a rock compression zone at some distance from the wellbore. This distance should be great enough to avoid the impairment of connectivity between the wellbore and the reservoir matrix. This requirement should be relatively easy to satisfy knowing something about the preexisting fracture pattern, which may be available from the currently deployed formation evaluation tools. The proppant placement schedule during refracturing also has to be addressed. We may have to pump in many volumes of the initial fracture to make sure that it was finally cleaned up before starting placement of a new proppant. The particle size of new proppant may not be the same as that of the proppant placed inside the initial fracture. It may be finer to provide better support of fracture surfaces. The schematic of refracturing and proppant replacement is shown in FIG. 4 and FIG. 5.

FIG. 5 shows a schematic of final fracture after formation unloading in the near wellbore zone by circulating chemically active fluid followed by refracturing. FIG. 5 shows a wellbore connected to the TGS reservoir resources through preexisting fractures (a). After unloading the reservoir rock near the initial fracture, refracturing and proppant replacement, the pre-existing fractures are open wider around the fracture part near the wellbore providing better connectivity to the reservoir matrix (b). The remote part of the fracture, which is used as storage of the residuals and replaced proppant, does not contribute to the fractured well productivity. The red boundary surrounds the unloaded reservoir volume with open wider pre-existing fractures. The reservoir rock is compressed inside the domain with a blue boundary, where the pre-existing fractures are closed.

Repeated Circulation-Refracturing Cycles.

The fluid circulation and refracturing sequences can be repeated a few times to achieve better formation unloading, initial fracture cleanup and proppant placement using the remote part of the fracture as a storage of used/waste materials, i.e. the residuals of destabilized reservoir rock, the proppant and the injected fluids. This can be accomplished immediately or later if the productivity of fractured well starts decreasing with reservoir depletion. The reservoir depletion is usually accompanied by the increase in the effective stresses and matrix compaction. In the case of TGS, the preexisting fractures will be closed first. The repeated circulation-refracturing cycles may be able to extend production from reservoir and to improve the ultimate gas recovery.

Coupling with Hydraulic Fracturing Monitoring.

The key component of proposed TGS fracturing technique is the creating underground circulation system inside hydraulically induced fracture, which can be used for the removal of shale rock material from the adjacent to dominant fracture region thus unloading the surrounding shale rock and enhancing the natural fracture network connectivity. The recent advancements in HFM indicate that the hydraulic fractures created in TGS formations interact with the pre-existing fracture network and have much more complex geometry than the conventional planar cracks investigated and modeled by the classical HF theory.

During multistage HF job execution and monitoring at TGS, the map of microseismic events is usually reconstructed. The aspect ratio of each dot cluster, which is also known as the Fracture Complexity Index or FCI, is widely used in the industry for the characterization of fracture geometry or, more accurately, the deviation of its geometry from an ideal planar fracture.

Based on many investigations, the microseismic event maps with wide dot clusters (or high FCI) are correlated with high fracture geometry complexity. The examples of fracture complexity are illustrated schematically in FIG. 8 showing four different types of hydraulic fracture interacting with natural fracture network.

FIG. 6 shows schematics of fracture complexity levels.

Right now, however, there is no credible technique for reconstructing geometry of hydraulic fracture and the proppant distribution inside it from the HFM well testing data. At the same time, there are dual porosity models, which can be calibrated although with huge uncertainty for capturing the fractured well production performance. The additional information about HF propagation is also obtained from the off-set observation wells, for example, by detecting the presence of fracturing fluid in these wells at some phase of stimulation. This information helps to reconstruct the fracture propagation pattern and trajectory.

The HFM technology based on microseismic event mapping thus provides useful means for the creation and optimization of underground circulation systems targeting the unloading TGS formation from natural and induced stresses. The schematic of such a system is outlined in FIG. 7. First, the multistage HF stimulation has to be conducted from one of the laterals until the connectivity with the second lateral placed in the reasonable proximity is established. After that the circulation of an active fluid inside the created fractures has to be conducted sequentially or simultaneously monitoring the shale rock material removal, the hydraulic conductivity of fractures, and the stress release in the formation. As soon as the unloading phase is finished, the flowback and fracture cleanup procedures have to be initiated until the system becomes ready for gas production.

FIG. 7 shows schematic of TGS circulating system for massive shale removal and formation unloading targeting the enhancement of pre-existing fracture network connectivity.

The circulation phase may be preceded by the injection of some buffer fluid, which would mitigate the effect of shale rock destabilization during the flowback/cleanup phase.

Application to Coal Bed Methane Production.

There is well known similarity of challenges between gas production from TGS and coal beds. Unloading coal seams from stresses is crucially important for the CBM production since the gas is kept inside the coal matrix in the absorbed state and can be released only with the reduction of stresses. The desorption mechanism can provide higher gas recovery factors than in the case of tight sandstone gas formations with the porosity in the range of 4-8% as shown in FIG. 8.

FIG. 9 shows gas release from coal beds versus pressure in comparison with gas production from tight sand formations. FIG. 9 shows tectonic fractures and stratigraphic controls on cleats. Fracture zone 95 and channel sand 96 can be seen.

The coal 9 seams usually have fractured structure with two systems of cleats, face cleats 90 and butt cleats 91, reflecting its geological origin and genesis as shown in FIG. 9.

The different scenarios of hydraulic fracturing in coal beds versus the horizontal stress anisotropy and orientation are shown in FIG. 10. The hydraulic fractures induced by stimulation can be oriented along the existing cleats as shown in FIG. 10, a b or can interact with the cleat system in a more complex manner creating complex single (FIG. 10, c) or multiple (FIG. 10, d) dominant fractures.

FIG. 10 shows hydraulic fracturing scenarios in coal bed versus the stress anisotropy and orientation: a—fracturing across face cleats, b—fracturing along face cleats, c—complex fracturing through both face and butt cleat systems with a single dominant fracture, d—complex fracturing with multiple dominant fractures.

The circulation system in coal seams can also be created with the help of hydraulic fracturing. This system then can be used for circulating an active fluid targeting destabilization and removal of coal from the adjacent to dominant fracture region.

The unloading of coal bed has to be customized and tuned versus its geometrical structure, stress state, permeability and cleats orientations. The HFM technology should provide additional information during planning and execution of coal bed stimulation and unloading.

According to some embodiments of the fluids that may be used in the current methods: the HF fluid used may be any conventional hydraulic fracturing fluid. The fluid may comprise a low amount of viscosifier. The loading of the viscosifier, for example described in pounds of gel per 1,000 gallons of carrier fluid, is selected according to the particulate size (due to settling rate effects) and loading that the fracturing slurry must carry, according to the viscosity required to generate a desired fracture geometry, according to the pumping rate and casing or tubing configuration of the wellbore, according to the temperature of the formation of interest, and according to other factors understood in the art. In certain embodiments, the low amount of the viscosifier includes a hydratable gelling agent in the carrier fluid at less than 20 pounds per 1,000 gallons of carrier fluid where the amount of particulates in the fracturing slurry are greater than 16 pounds per gallon of carrier fluid. In certain further embodiments, the low amount of the viscosifier includes a hydratable gelling agent in the carrier fluid at less than 20 pounds per 1,000 gallons of carrier fluid where the amount of particulates in the fracturing slurry are greater than 23 pounds per gallon of carrier fluid. In certain embodiments, a low amount of the viscosifier includes a visco-elastic surfactant at a concentration below 1% by volume of carrier fluid. In certain embodiments a low amount of the viscosifier includes values greater than the listed examples, because the circumstances of the fluid conventionally utilize viscosifier amounts much greater than the examples. For example, in a high temperature application with a high proppant loading, the carrier fluid may conventionally indicate the viscosifier at 50 lbs of gelling agent per 1,000 gallons of carrier fluid, wherein 40 lbs of gelling agent, for example, may be a low amount of viscosifier. One of skill in the art can perform routine tests of fracturing slurries based on certain particulate blends in light of the disclosures herein to determine acceptable viscosifier amounts for a particular embodiment of the fluid.

In certain embodiments, the HF fluid may include an acid. The fracture is illustrated as a traditional hydraulic double-wing fracture, but in certain embodiments may be an etched fracture and/or wormholes such as developed by an acid treatment. The carrier fluid may include hydrochloric acid, hydrofluoric acid, ammonium bifluoride, formic acid, acetic acid, lactic acid, glycolic acid, maleic acid, tartaric acid, sulfamic acid, malic acid, citric acid, methyl-sulfamic acid, chloro-acetic acid, an amino-poly-carboxylic acid, 3-hydroxypropionic acid, a poly-amino-poly-carboxylic acid, and/or a salt of any acid. In certain embodiments, the carrier fluid includes a poly-amino-poly-carboxylic acid, and is a trisodium hydroxyl-ethyl-ethylene-diamine triacetate, mono-ammonium salts of hydroxyl-ethyl-ethylene-diamine triacetate, and/or mono-sodium salts of hydroxyl-ethyl-ethylene-diamine tetra-acetate. The selection of any acid as a carrier fluid depends upon the purpose of the acid—for example formation etching, damage cleanup, removal of acid-reactive particles, etc., and further upon compatibility with the formation, compatibility with fluids in the formation, and compatibility with other components of the fracturing slurry and with spacer fluids or other fluids that may be present in the wellbore.

In certain embodiments, the HF fluid includes particulate materials generally called proppant. Proppant involves many compromises imposed by economical and practical considerations. Criteria for selecting the proppant type, size, and concentration is based on the needed dimensionless conductivity, and can be selected by a skilled artisan. Such proppants can be natural or synthetic (including but not limited to glass beads, ceramic beads, sand, and bauxite), coated, or contain chemicals; more than one can be used sequentially or in mixtures of different sizes or different materials. The proppant may be resin coated, or pre-cured resin coated. Proppants and gravels in the same or different wells or treatments can be the same material and/or the same size as one another and the term proppant is intended to include gravel in this disclosure. In general the proppant used will have an average particle size of from about 0.15 mm to about 2.39 mm (about 8 to about 100 U.S. mesh), more particularly, but not limited to 0.25 to 0.43 mm (40/60 mesh), 0.43 to 0.84 mm (20/40 mesh), 0.84 to 1.19 mm (16/20), 0.84 to 1.68 mm (12/20 mesh) and 0.84 to 2.39 mm (8/20 mesh) sized materials. Normally the proppant will be present in the slurry in a concentration of from about 0.12 to about 0.96 kg/L, or from about 0.12 to about 0.72 kg/L, or from about 0.12 to about 0.54 kg/L.

The foregoing disclosure and description of the invention is illustrative and explanatory thereof and it can be readily appreciated by those skilled in the art that various changes in the size, shape and materials, as well as in the details of the illustrated construction or combinations of the elements described herein can be made without departing from the spirit of the invention.

Claims

1. A method for use in a wellbore, comprising:

a. providing a hydraulic fracturing fluid to initiate at least a fracture in a subterranean formation, wherein the subterranean formation comprises a rock material;

b. injecting a treatment fluid in the fracture to at least partially remove the rock material; and

c. repeating the step of fracturing the subterranean formation.

2. The method of claim 1, further comprising subsequently after step b, circulating the treatment fluid in the subterranean formation.

3. The method of claim 2, further comprising re-circulating the treatment fluid in the subterranean formation.

4. The method of claim 2, further comprising subsequently removing the treatment fluid from the wellbore.

5. The method of claim 4, wherein the removing step is done through another wellbore.

6. The method of claim 4, wherein the treatment fluid further comprises at least partially the rock material.

7. The method of claim 5, wherein the two wellbores are substantially parallel.

8. The method of claim 7, wherein the two wellbores are horizontal.

9. The method of claim 7, wherein the two wellbores are vertical.

10. The method of claim 1, wherein the rock material is shale.

11. The method of claim 10, wherein the injecting step creates destabilization of the shale.

12. The method of claim 1, further comprising subsequently after step b, creating a cavity in the subterranean formation.

13. The method of claim 1, wherein the hydraulic fluid further comprises proppant.

14. A method for use in a wellbore from a shale formation, comprising:

a. providing a hydraulic fracturing fluid to initiate at least a fracture in the shale;

b. injecting a treatment fluid in the fracture to at least partially destabilize and remove the shale; and

c. repeating the step of fracturing the shale.

15. The method of claim 14, further comprising subsequently after step b, circulating the treatment fluid in the shale.

16. The method of claim 15, further comprising re-circulating the treatment fluid in the shale.

17. The method of claim 15, further comprising subsequently removing the treatment fluid from the wellbore.

18. The method of claim 14, wherein the hydraulic fracturing fluid in step a comprises proppant.

19. The method of claim 14, wherein the hydraulic fracturing fluid in step c comprises proppant.

20. A method for use in a shale formation, comprising:

a. providing a hydraulic fracturing fluid through a first wellbore to initiate at least a fracture in the shale;

b. injecting a treatment fluid in the fracture through the first wellbore to at least partially destabilize and remove the shale;

c. circulating the treatment fluid trough the shale to a second wellbore; and

d. removing the treatment fluid through the second wellbore.

21. The method of claim 20 further comprising repeating the step of fracturing the shale.

22. The method of claim 20, wherein the two wellbores are substantially parallel.

23. The method of claim 22, wherein the two wellbores are horizontal.

24. The method of claim 22, wherein the two wellbores are vertical.