Patent Application
20130146293
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.
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.
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.
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
In
The proposed method disclosed herewith for HF of TGS involves the following steps and procedures:
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.
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
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.
The primary functions of the initial injected and/or circulated treatment fluids are to:
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:
Additional key functions of the fluids to be deployed as a component of the conceived completion procedure are:
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:
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):
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”.
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
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
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
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.
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
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
The different scenarios of hydraulic fracturing in coal beds versus the horizontal stress anisotropy and orientation are shown in
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.
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/US2011/035455 | 5/6/2011 | WO | 00 | 2/28/2013 |
| Number | Date | Country | |
|---|---|---|---|
| 61395337 | May 2010 | US |
