Patent Grant
11933161
The present disclosure generally relates to oilfield equipment and, in particular, to downhole tools, drilling and related systems and techniques for estimating formation and treatment parameters. More particularly still, the present disclosure relates to methods and systems for estimating formation and treatment parameters by collecting treatment data, such as pressure and fluid flow, and estimating formation and treatment parameters, such as closure stress, leak-off parameters, dynamic fracture permeability, average fracture width, average fracture length, size of diverter particles, limits for remedial treatment pressures and flow rates, friction regimes, and diverter efficiency.
In order to produce formation fluids from an earthen formation, wellbores can be drilled into the earthen formation to a desired depth. After drilling a wellbore, casing strings can be installed in the wellbore providing stabilization to the wellbore and keeping the sides of the wellbore from caving in on themselves. Multiple casing strings can be used in completion of a deep wellbore. A small space between a casing and untreated sides of the wellbore (generally referred to as an annulus) can be filled with cement. After the casing is cemented in place, perforating gun assemblies can be used to form perforations through the casing and associated cement, and into the earthen formation. (Of course, perforations can also be formed in uncased wellbores which do not have a casing or cement). A set of perforations can be referred to as a production stage, which includes a longitudinal distance along the wellbore at a location in the wellbore where formation fluids can be produced into a production string installed in the wellbore. As used herein, a “production stage” refers to a location along the wellbore where it is desirable to produce fluids, whether the location is in a vertical, a horizontal, or an inclined portion of the wellbore. Multiple perforations may be formed at each “production stage” to allow production fluids entrance into the wellbore. Some wellbores include multiple production stages at several locations along the wellbore.
Generally, multiple perforations are formed at each production stage, with each production stage being fractured at the perforations. The wellbore and/or perforations can be plugged before a next production stage is perforated, fractured, and plugged. This sequence can continue until all production stages in the wellbore are perforated and fractured. It should be understood that various sequences of fracturing the production stages can be performed, such as random and/or out of sequence fracturing operations that fracture a current stage and then can proceed to fracturing a next stage, with the next stage being above or below the current stage. When all the stages are perforated and fractured, the plugging material (or plugs) can be removed from the wellbore to facilitate production of formation fluids. However, proppant deposited in the fractures can remain in the fractures to keep them from closing.
A fracturing operation can require several design parameters (e.g. fracture closure pressure, fracture gradient, fluid leakoff coefficient, fluid efficiency, formation permeability, formation conductivity, formation flow capacity, reservoir pressure, an expected fracture geometry, etc.) to be determined and/or estimated prior to initiating the operation. Estimating these parameters can be based on data from similar formations, simulations, etc. and can help the fracturing operation begin within suitable ranges for these parameters, but these estimates may not be accurate for the current wellbore. Actual testing of the wellbore can be performed to determine these parameters, such as a minifrac test, which is a small fracturing treatment performed before the main hydraulic fracturing treatment to acquire job design and execution data and confirm a predicted response of the treatment interval. The intent is to break down the formation to create a short fracture during the injection period, and then to observe closure of the fracture system during the ensuing falloff period. These tests can be performed to obtain the design parameters. However, the minifrac tests can take valuable well system time in addition to the actual treatment time.
Therefore, it will be readily appreciated that improvements in the arts of determining design parameters for fracturing operations are continually needed.
Various embodiments of the present disclosure will be understood more fully from the detailed description given below and from the accompanying drawings of various embodiments of the disclosure. In the drawings, like reference numbers may indicate identical or functionally similar elements. Embodiments are described in detail hereinafter with reference to the accompanying figures, in which:
The disclosure may repeat reference numerals and/or letters in the various examples or Figures. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Further, spatially relative terms, such as beneath, below, lower, above, upper, uphole, downhole, upstream, downstream, and the like, may be used herein for ease of description to describe one element or feature's relationship to another element(s) or feature(s) as illustrated, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the wellbore, the downhole direction being toward the toe of the wellbore. Unless otherwise stated, the spatially relative terms are intended to encompass different orientations of the apparatus in use or operation in addition to the orientation depicted in the Figures. For example, if an apparatus in the Figures is turned over, elements described as being “below” or “beneath” other elements or features would then be oriented “above” the other elements or features. Thus, the exemplary term “below” can encompass both an orientation of above and below. The apparatus may be otherwise oriented (rotated 90 degrees or at other orientations) and the spatially relative descriptors used herein may likewise be interpreted accordingly.
Moreover even though a Figure may depict a horizontal wellbore or a vertical wellbore, unless indicated otherwise, it should be understood by those skilled in the art that the apparatus according to the present disclosure is equally well suited for use in wellbores having other orientations including vertical wellbores, slanted wellbores, multilateral wellbores or the like. Likewise, unless otherwise noted, even though a Figure may depict an offshore operation, it should be understood by those skilled in the art that the method and/or system according to the present disclosure is equally well suited for use in onshore operations and vice-versa. Further, unless otherwise noted, even though a Figure may depict a cased hole, it should be understood by those skilled in the art that the method and/or system according to the present disclosure is equally well suited for use in open hole operations and/or other types of well completions (e.g. liners, slotted liners, sliding and pre-perforated sleeves, screens, etc.).
As used herein, the words “comprise,” “have,” “include,” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods also can “consist essentially of” or “consist of” the various components and steps. It should also be understood that, as used herein, “first,” “second,” and “third,” are assigned arbitrarily and are merely intended to differentiate between two or more objects, etc., as the case may be, and does not indicate any sequence. Furthermore, it is to be understood that the mere use of the word “first” does not require that there be any “second,” and the mere use of the word “second” does not require that there be any “first” or “third,” etc.
The terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.
Generally, this disclosure provides a system and method to determine closure pressure and/or an average fracture permeability that can include, flowing a fracturing fluid into the wellbore during a fracturing operation of at least one stage and forming a fracture, sensing fluid pressure and a flow rate of the fracturing fluid during the fracturing operation and communicating the sensed data to a controller, plotting data points of the sensed data to a visualization device which is configured to visually present the data points to an operator as a plot, fitting a curve to the data points which represent statistically-relevant minimum pressure data at various flow rates, determining an intercept of the first curve with a zero flow rate axis of the plot, determining the closure pressure based on a pressure value of the intercept, and determining an average fracture permeability based on the closure pressure.
Sensors 92 and 94 can be used to collect wellbore parameters (pressure, temperature, strain, etc.) as well as fluid parameters (pressure, temperature, flow rate, etc.). In
The wellbore production system 10 in
Wellbore 12 may be formed of single or multiple bores, extending into the formation 14, and disposed in any orientation (e.g. vertical, inclined, horizontal, combinations of these, etc.). The wellbore production system 10 can also include multiple wellbores 12 with each wellbore 12 having single or multiple bores. The rig 18 may be spaced apart from a wellhead 40, as shown in
Multiple production stages 60, 62, 64 are shown in a horizontal portion of the wellbore 12. Fractures 50, 52, 54 for stages 60, 62, 64, respectively, are shown radially extending from perforations 36 into the formation 14. The wellbore system 10 is shown in a production configuration after a completion operation has been performed on the wellbore 12. A production string 30 with multiple screen assemblies positioned at each stage 60, 62, 64 is shown where fluids from the formation 14 can enter the production string 30 through the screen assemblies and be produced to the surface 16 and/or rig 18. It should be understood that
In performing the completion operation on the wellbore 12, multiple fracturing operations can be used to form fractures 50, 52, 54. Generally, these fractures are formed sequentially one at a time starting with the lowermost stage 64 and working up to the uppermost stage 60. There are also several methods and systems available for performing fracturing operations on multiple production stages out of sequence, such as fracturing an upper production stage then fracturing a lower production stage, and/or randomly selecting the order of fracturing the stages 60, 62, 64. One possible process for fracturing the stages 60, 62, 64 is shown in
However, as provided in this disclosure, these parameters can be determined and continually updated during the fracturing operation without requiring separate test operations prior to beginning the fracturing operations. In this approach, a fracturing operation is designed with estimated parameters that can be obtained through simulations, historical data from other wellbores and similar earthen formations, logged data from the current wellbore 12, etc. Once these estimated parameters are incorporated into the fracturing operation design, then the operator can begin a fracturing operation for a particular stage, such as stage 64 which is shown being fractured in
As the fracturing process for stage 64 begins, a proppant laden fluid 70 can be pumped at a desired pressure into the perforations 36 at stage 64. Generally, the characteristics of each perforation 36 and the formation into which the perforation extends can vary between each perforation 36. Therefore, at the same fluid pressure, some perforations may accept more fluid 70 than others in stage 64 possibly causing variations in fracture geometries. Some flow paths through the perforations may accept too much flow thereby hampering the fracturing process by preventing adequate pressure build up necessary for forming the fracture 54. It can be desirable to cause each perforation 36 to accept generally the same amount of fluid 70 at generally the same pressure.
This can be accomplished by depositing diverter particulates in the perforations and any fractures that are formed. Perforations that accept larger amounts of the fluid 70 will also receive larger amounts of diverter particulates, thereby increasingly restricting the flow of fluid 70 at a greater rate than perforations that accept less of the fluid 70. This may result in average fluid flow through each of the perforations, and therefore, can result in more uniform fracturing geometries for fracture 54. Throughout the fracturing process of stage 64, data points of pressure and flow rate (and/or fluid volume pumped) can be collected at periodic intervals (e.g. milliseconds, seconds, etc.) and recorded in a database in a processing system, displayed on a computer screen of the processing system, transmitted to a remote processing system, etc. The recorded data can be used to determine actual fracturing process parameters and refine the fracturing process design while fracture 54 is being formed. The actual fracturing process parameters can include such things as closure stress, leak-off parameters, dynamic fracture permeability, average fracture width, average fracture length, size of diverter particles (and/or proppant), limits for remedial treatment pressures and rates, understanding friction regimes, diverter efficiency criteria, etc. These actual parameters can be used to provide a more accurate fracturing process design for subsequent stages in the wellbore 12, such as stages 62, 60.
After the fracture 54 has been formed, it may be desirable to perform additional perforating and fracturing operations of additional stages (e.g. stages 62, 60). With the actual fracturing process parameters determined from fracturing stage 64, more accurate fracturing process designs can be established for these additional stages. With the principles of this disclosure, the fracturing process design of the additional stages can be rechecked and modified as needed while the fracturing operations are in progress.
To progress to the next stage 62, it is normally desirable to plug the previous stage by installing a plugging material 72 (e.g. bridge plug, frac plug, organic material, diverter particulates, etc.) between the stages 64 and 62. Plugging the stage 64 prevents (or at least minimizes) fracturing fluid 70, intended for fracturing stage 62, from being lost in the previously fractured stage 64. This plugging material 72 can be a frac plug and/or a bridge plug installed in the wellbore 12, as well as various other methods for diverting the fracturing fluid 70 away from the production stage 64 and into the perforations 36 in the production stage 62 for forming the fracture 52, such as depositing diverter particulates in the fracture and/or perforations. Again, data points of pressure and flow rate (and/or fluid volume pumped) can be collected at periodic intervals and recorded in a database in a processing system (e.g. a controller 98), displayed on a computer screen of the processing system, transmitted to a remote processing system, etc. The recorded data can be used to determine actual fracturing process parameters and refine the fracturing process design while fracture 52 is being formed. The actual fracturing parameters for stage 62 can be different than the parameters for stage 64. Therefore, this process provides improvement over other methods and systems in that the fracturing parameters can be continually refined throughout the fracturing of multiple stages in the wellbore 12.
As the fracturing process continues, more and more data points 74 can be collected and plotted, and yielding a representative distribution as seen in
For purposes of discussion, the example given in
To determine a closure pressure PC of a formation 14 at a particular stage, such as stages 60, 62, 64, the data points 74 can be collected during the fracturing process. With a sufficient amount of data points 74 collected, the closure pressure PC can be estimated based on lower data points 74 for various slurry flow rates. This can be referred to as “statistically-relevant minimum pressure” data points 74 for the various slurry flow rates. As used herein, “statistically-relevant minimum pressure” refers to the lowest data point 74 for multiple slurry flow rates that can be intersected by a curve 80 (e.g. a line) through the other lower data points for other ones of the multiple slurry flow rates. The curve 80 is established such that it intersects a representative number of the data points 74 that are proximate the lowest data points 74 for each slurry flow rate (or at least representative sampling of slurry flow rates spanning the slurry flow rate range of the plot). With the curve 80 established, then the closure pressure PC can be determined by determining where the curve 80 intersects the “zero” slurry flow rate axis. This intercept point 76 of the flow rate axis provides the estimated closure pressure PC of the current stage being fractured and/or a stage that has already been fractured.
A slope of the curve 80 can be determined in this example from a visualization tool (e.g. display, hardcopy plot, etc.) by fitting the curve to the data points 74 for statistically-relevant minimum pressure at various slurry flow rates. In this example, the curve 80 is a line. Equation (1) below can represent the equation for the line 80, where the slurry rate is a function of pressure:
Where {dot over (Q)} is the slurry rate, hf is the fracture height, Lf is the fracture half length, E is the Young's modulus, tpump duration of time the stage pump is pumping, v is the Poisson's ratio, P is the bottom hole pressure assuming negligible friction in the fracture and PC is the closure pressure obtained from the intercept point 76 of the line 80 with the “zero” slurry flow rate line.
As shown by Equation (1) above, the slope80 for the curve 80 (or line 80 in this example) can be represented by Equation (2) below:
The fracture height hf, Young's modulus E, Poisson's ratio v can be obtained from historical data. The slope80 can be determined directly from the fitted line 80, thus yielding a value for the slope80. With the value of the slope80 also known, then Equation (2) can be used to determine the average fracture half length Lf, which can be hundreds of meters long, such as the “Cordell” formation which is estimated at 344 meters long.
The average fracture half length Lf can then be used to calculate a dynamic average fracture width wf represented by Equation (3) below:
The dynamic average width wf can be used to calculate in real time a desired size for diverter particulates 72 which can be pumped along with the fracturing fluid 70. When it is desired to divert the fracturing fluid, an appropriate bridging criteria for the diverter particulates 72 to enter the fracture, such as dp/wf>1 where dp is the average particle size (d50), can be used to determine desired diverter particulates 72 used to help ensure proper diversion when pumped with the fracturing fluid 70.
As the pressure and slurry rate are increased during the fracturing process, a fracture (e.g. fractures 50, 52, 54) can be formed. The clustering of data points 74 can be seen in
The slurry rate can also be represented by the Equation (4) below:
Where {dot over (Q)} is the slurry rate, hf is the average fracture height, wf is the dynamic average width, Lf is the average fracture half length, Kf is the average fracture permeability, μ is the fracturing fluid viscosity, P is the bottom hole pressure assuming negligible friction in the fracture and PC is the closure pressure obtained above from the intercept point 76 of the line 80 with the “zero” slurry flow rate line. The slope82 can be used to compute the average fracture permeability Kf as given by equation (5) below
The slope82 can be determined directly from the fitted line 82, thus yielding a value for the slope82, and then Equation (5) can be used to determine the average fracture permeability Kf. Additionally, Fracture Conductivity can be estimated using the average fracture permeability Kf and the dynamic average width wf.
When fracturing multiple stages in a wellbore 12 in a single trip in the wellbore as well as multiple perforation clusters within a stage, it may be desirable to divert the fracturing fluid 70 away from a fracture that has already been formed in one stage to perforations in another stage (or another perforation cluster in the same stage) where the next fracture is to be formed. This diversion process can be used to restrict flow of the fracturing fluid 70 from existing fractures sufficiently enough to allow downhole pressure to increase to a point that the fracturing fluid can fracture the next stage (or perforation cluster). If flow is not sufficiently restricted, downhole pressure may not increase to a fracturing pressure, thereby preventing further fracturing. Therefore, it can be valuable to determine if the diversion process was successful in forming a diversion that sufficiently restricts flow of fracturing fluid 70 to any existing fractures and/or loss zones in the wellbore 12.
As the diverter material is deposited in the fracture, the flow through the fracture should begin to be reduced even if the pressure increases, which is generally indicated by the arrow 88. If the clustering of data points 74 begin to populate the plot along the arrow 88, then this can indicate that the diverter material 72 being deposited (such as diverter particulates, proppant, etc.) in the newly formed fracture is beginning to restrict flow of the fracturing fluid 70 into the newly formed fracture, which can be the desired outcome for a diversion process. However, if the clustering of data points continues to populate the plot along the arrow 86, then this may indicate that the slurry rate of fluid 70 into the newly formed fracture is not being significantly impacted by the deposited diverter material. This can indicate that the diverter material 72 is not sufficiently restricting flow of fluid 70 into the newly formed fracture and that forming the next fracture with desired fracture geometries may not be possible until the flow restriction is improved. The real-time indication of the integrity of the diverter can initiate corrective actions in real-time to improve diversion, such as increase diverter particle size, change diverter particle concentration, change diverter particle material, etc.
A method of determining closure pressure in a wellbore is provided which can include operations for flowing a fracturing fluid into the wellbore during a fracturing operation of at least one stage of the wellbore, thereby forming a fracture at a location of the stage, sensing pressure in the wellbore via a sensor during the fracturing operation and communicating the sensed pressure data to a controller, sensing a flow rate of the fracturing fluid via a sensor during the fracturing operation and communicating the sensed flow rate data to the controller, with the controller plotting data points of the sensed pressure data vs. the sensed flow rate data to a visualization device which is configured to visually present the plotted data points to an operator as a plot, fitting a first curve to the data points which represent statistically-relevant minimum pressure data at various flow rates, determining an intercept of the first curve with a zero flow rate axis of the plot, and determining the closure pressure based on a pressure value of the intercept.
For any of the foregoing embodiments, the method may include any one of the following elements, alone or in combination with each other:
The operations can also include flowing the fracturing fluid into the wellbore during fracturing operations of multiple stages of the wellbore, plotting the data points for the fracturing operations of the multiple stages, and/or determining first and second closure pressures for respective first and second stages of the multiple stages, where the first and second closure pressures can be different.
The operations can also include determining an average half length of the fracture based on a slope of the first curve, determining a dynamic average width of the fracture based on the average fracture half length and the closure pressure, and/or determining a size of diverter particulates based on the dynamic average width.
The operations can also include fitting a second curve to data points which can represent statistically relevant maximum pressure data at various flow rates, determining an average fracture permeability based on the slope of the second curve, the average fracture half length, and the dynamic average width, and/or modifying a production operation based on the average fracture permeability, and/or determining at least one selected from the group consisting of a fracture conductivity, a fracture gradient, a fluid leakoff coefficient, a fluid efficiency, a formation permeability, a formation conductivity, a formation flow capacity, a reservoir pressure, and expected fracture geometries based on a combination of the average fracture permeability, the average fracture half length, and/or the dynamic average width.
The operations can also include carrying diverter particulates in the fracturing fluid and depositing the diverter particulates in the fracture, thereby diverting the fracturing fluid away from the fracture, where the plotting can further comprise plotting the data points as the diverter particulates are being deposited in the fracture and determining an integrity of a diversion formed by the deposited diverter particulates based on a progression of the plotted data points displayed on the plot.
The operations can also include where the closure pressure is based on measurements taken during the fracturing operation of the stage, and where a test fracturing operation is not required prior to beginning the fracturing operation of the at least one stage.
The operations can also include where the at least one stage comprises multiple stages and the closure pressure is adjusted based on the sensed pressure and flow rate data measured during fracturing operations of the multiple stages.
Another method for determining an integrity of a diversion in a multi-stage fracturing operation is provided which can include operations for flowing a fracturing fluid into the wellbore during a fracturing operation of a first stage of the wellbore, thereby forming a fracture at a location of the first stage, sensing fracturing fluid pressure via a sensor during the fracturing operation and communicating the sensed pressure data to a controller, sensing a flow rate of the fracturing fluid via a sensor during the fracturing operation and communicating the sensed flow rate data to the controller, the controller plotting data points of the sensed pressure data vs. the sensed flow rate data to a visualization device which is configured to visually present the plotted data points to an operator as a plot, carrying diverter particulates in the fracturing fluid and depositing the diverter particulates in the fracture, thereby diverting the fracturing fluid away from the fracture, plotting the data points as the diverter particulates are being deposited in the fracture and determining an integrity of a diversion formed by the deposited diverter particulates based on a progression of the plotted data points displayed on the plot.
For any of the foregoing embodiments, the method may include any one of the following elements, alone or in combination with each other:
The operations can also include where the fracturing fluid pressure is the pressure of the fracturing fluid at a downhole location, or where the fracturing fluid pressure is determined by sensing a pressure of the fracturing fluid proximate the earth's surface and compensating for hydrostatic/friction losses in the fracturing fluid as the fracturing fluid is pumped into the wellbore to approximate pressure of the fracturing fluid at a downhole location.
Furthermore, the illustrative methods described herein may be implemented by a system comprising processing circuitry that can include a non-transitory computer readable medium comprising instructions which, when executed by at least one processor of the processing circuitry, causes the processor to perform any of the methods described herein.
Although various embodiments have been shown and described, the disclosure is not limited to such embodiments and will be understood to include all modifications and variations as would be apparent to one skilled in the art. Therefore, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed; rather, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the disclosure as defined by the appended claims.
The present application is a Divisional of U.S. application Ser. No. 16/349,385, filed May 13, 2019, which is a U.S. National Stage patent application of International Patent Application No. PCT/US2017/013495, filed on Jan. 13, 2017, the disclosure of each of which is hereby incorporated by reference in its entirety.
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| Number | Date | Country | |
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| Parent | 16349385 | US | |
| Child | 17510623 | US |
