EA042125B1 - MULTI-STAGE HYDRAULIC FRACTURING TREATMENT WITH REAL-TIME ADJUSTMENT - Google Patents

Description

Technical field

Hydraulic fracturing (hereinafter, hydraulic fracturing) is a method of stimulating well flow by creating fractures within a hydrocarbon containing formation by pumping fluid into it at a pressure exceeding the formation fracture pressure. For stimulation, a proppant is also delivered to the fracture along with the fluid, which prevents the fracture from closing after the pressure is released at the end of the treatment. After the treatment and commissioning of the well, hydrocarbons flow from the reservoir into the wellbore through the fractures formed. The main purpose of hydraulic fracturing is to increase well productivity.

Unconventional resources such as shale gas or shale oil require massive multi-stage hydraulic fracturing operations in horizontal wells. This hydraulic fracturing method maximizes wellbore coverage and reservoir contact. Fracturing jobs can be designed based on reservoir data, volume of proppant and acid to be injected, target well productivity, etc. However, reservoir characterization uncertainties can complicate the process of designing and effectively executing hydraulic fracturing operations to maximize the total amount of hydrocarbons recovered from a given reservoir.

Brief description of the entity

This entity summary contains a selection of concepts that are detailed below. This description is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid to limiting the scope of the claimed subject matter.

In one aspect, the embodiments described herein relate to methods for treating a subterranean formation that comprise: (1) selecting a wellbore for a multi-stage fracturing treatment, developing an initial multi-stage fracturing treatment design, defining one or more criteria evaluation of hydraulic fracturing and development of a model of the propagation of tubular waves in the wellbore based on the initial design of hydraulic fracturing; (2) commencement of part of the original work design; (3) providing one or more tube waves in the wellbore and monitoring one or more reflections of one or more tube waves and calculating the number of open fractures and fracture geometry parameters in accordance with the tube wave propagation model; (4) performing real-time estimation of fracture geometry parameters by calculating one or more flow rates when injected into a series of open fractures and simulating the fracturing process for a series of open fractures using a multi-stage hydraulic fracturing simulator; (5) adjusting the multi-stage fracturing simulator until the number of open fractures, one or more injection rates, and fracture geometry parameters from step (3) match the real-time estimate of fracture geometry parameters from step (4), to provide an adjusted fracturing simulator; (6) calculation of fracture geometry parameters using the corrected hydraulic fracturing simulator to develop a measurement-based (real-time controlled) revised work design. Then (7) calculating the difference between the original work design and the revised work design based on the measurement results; and (8) doing one of the following: checking that the difference obtained in step (7) is below a prescribed variation for one or more of the fracturing job evaluation criteria, and continuing with the original work plan; or refine the original work design and repeat steps (6) and (7) until the difference obtained in step (7) falls below the prescribed variation for one or more of the fracturing job evaluation criteria, and proceed with the revised version of the original design works; and (9) repeating steps (3)-(8) until completion of the multi-stage fracturing treatment. These implementation options allow you to change the design of works with the implementation of the main criteria for evaluating these works without stopping the hydraulic fracturing operation.

Other aspects of the claimed subject matter will be clear from the following description and the appended claims.

Brief description of graphic materials

In FIG. 1 is a flow chart showing a hydraulic fracturing operation in accordance with embodiments of the invention.

In FIG. 2 is a diagram illustrating tube wave propagation detection of fractures in a wellbore, in accordance with embodiments of the invention.

In FIG. 3 is a graphical illustration of the deconvolution of tube wave pressure fluctuations in accordance with embodiments of the invention.

In FIG. 4 is a diagram illustrating the theoretical basis for calculating the injection rate split into a set of open fractures in accordance with embodiments of the invention.

In FIG. 5 is a diagram showing an example of a computerized system for implementing methods in accordance with the invention.

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In FIG. 6 is a graphical illustration of a change in real-time fracturing operation in accordance with embodiments of the invention.

In FIG. 7 is a graphical illustration of a change in real-time fracturing operation in accordance with embodiments of the invention.

Detailed description

In one aspect, the embodiments described herein relate to methods for designing and executing hydraulic fracturing operations that use tube wave analysis by combining a flow split simulator and a multi-stage hydraulic fracturing (MHF) simulator to optimize operation design parameters. In the context of this document, a tube wave is a periodic pressure oscillation during which alternating compression and rarefaction propagate through a medium or over the surface of a medium without material transfer; it is also known as pressure wave or Stoneley wave. In one or more embodiments, the methods may be directed to monitoring, controlling, evaluating, and improving fracturing operations in real time. In some embodiments, the methods may also comprise performing one or more corrective actions to change the work design in real time.

As modeling techniques, software, and hardware advance, the ability to optimize designs before work begins and in real time becomes more feasible. One of the cost-effective methods of hydraulic fracturing is multi-stage hydraulic fracturing, in which multiple fractures can be created during one stage of injection. A hydraulic fracturing design may include the implementation of multi-stage hydraulic fracturing simulators to simulate multiple fractures in real time, which may also include algorithms to simulate flow sharing between fractures. However, such approaches are often based on well logs and other primary measurements recorded when tools are installed in the wellbore. The use of raw data leads to an unacceptably high level of measurement uncertainty, which can limit the reliability of predicting the open or closed state of fractures as the injected fluids separate and redistribute within the wellbore. As a result, work designs may require corrective measures to control aspects such as the placement of proppants and other materials in fractures that degrade hydrocarbon permeability and production rates.

The methods used in accordance with the invention can be used to design hydraulic fracturing, possibly involving numerical models of hydraulic fracturing and acidizing, which can help place the proppant without end shielding (or proppant bridging) and obtain the desired geometry and conductivity for fractures and / or channels. In one or more embodiments, the methods may use tube wave analysis in conjunction with a flow-sharing simulator and a multistage hydraulic fracturing simulator to provide a low-cost, wireless approach to open/closed fracture detection that can be performed periodically or in real time during a fracturing operation. In some embodiments, the tubular wave analysis may include real-time monitoring of the tubular waves reflected in the multi-stage hydraulic fracturing process.

Tube waves are boundary waves that occur in cased wells when a Rayleigh wave collides with the wellbore and disturbs the fluid in the wellbore. The tube wave travels down the wellbore along the interface between the fluid in the wellbore and the wellbore wall. Because the tube wave is associated with the formation through which it passes, it can perturb the formation through open fractures crossing the wellbore, providing a compression effect that provides secondary tube waves that bounce up and down from the fracture location. The intercepted secondary tube waves may contain signatures to identify open fractures, as well as an amplitude qualitatively related to length and width, such as the volume of fluid-filled fracture space, in addition to other characteristics such as fracture closure pressure, fracture initiation pressure, etc. P. Tube waves can also be used to detect other objects such as obstacles, pipe sections of various diameters, perforations and open cracks.

In practice, secondary trumpets can be recovered from deconvolution of primary trumpets by determining arrival times and peaks. This time and magnitude change in a predictable way, and this change can be analyzed with depth. Advanced tube wave processing algorithms (e.g., cepstral analysis) can also be used to extract data from tube waves to separate multiple fracture locations from the wellbore, along with pressure source control mechanisms, including pump noise, active pulse sources, etc. Examples of tube wave analysis are described in more detail in US Pat. No. 4,831,600.

In one or more embodiments, the methods may include using a flow split simulator to determine the amount of injected slurry entering each fracture.

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Optimization of a multi-stage hydraulic fracturing project

Multi-stage fracturing operations according to the invention comprise the following general steps: selecting a potential multi-stage fracturing treatment option, collecting treatment-related data, and creating an initial job design that can be recalibrated from the results of real-time data collection. In FIG. 1 is a block diagram illustrating the optimization of a multi-stage hydraulic fracturing design. In accordance with the method, starting at step 102, a wellbore or formation is selected for fracturing treatment, data related to the operation are collected, an initial work design is created, an initial work design is established, and, based on the initial work design, a tube wave propagation model is created in wellbore.

Operation related data collected may include mineralogical information, stress profiles, Young's modulus, and formation leakage for each formation under study. Initial fracturing design may include standard fracturing parameters such as fluid composition, clean fracturing fluid type, clean fluid fractions, proppant change programs, injection rates, recommended fracture pressures, equipment types, zone isolation (if required) and so on.

In accordance with the original work design, part of the work is performed by performing one stage of the fracturing treatment at stage 104, while the performance of the work in the wellbore is monitored using tube wave analysis at stage 106. The tube wave analysis at stage 106 includes providing one or more tube waves in the wellbore, monitoring one or more reflections of one or more tube waves, and calculating the number of open fractures and fracture geometry parameters based on the tube wave propagation model.

In step 108, optimization begins with real-time monitoring of tube wave reflections to determine the depth and/or number of open fractures at the wellbore, in addition to the associated fracture injection rates. As fractures are monitored, data is also monitored using one or more algorithms that estimate the distribution of injection rates between open fractures in real time in conjunction with a multi-stage hydraulic fracturing simulator to determine the parameters of the respective fractures. The fracture parameters obtained in step 108 are analyzed in step 110 to determine if there is an error between the tube waves observed in step 106 and the results of the fracturing simulator from step 108. to the data and parameters operation of the fracturing simulator in step 112.

After calibrating the fracturing simulator, the method proceeds to step 114 where the variation of the measured data for the performance criterion is compared to the performance criterion established in the original job design. In one or more embodiments, the performance criteria for a multi-stage fracturing treatment may include a given number of fractures for a given well or a given interval, percentage of proppant injected, fracture lengths, injection rates, and the like.

In step 116, depending on the degree of variation between the measurement-based work design and the original work design, the work parameters may be modified by adjusting a number of variables such as injection flow, proppant concentration, proppant size, fiber additives, fluid type, amount of fluid additives, etc., to reduce the variation of the respective performance evaluation criterion.

After the initial performance criterion is satisfied, the method proceeds to step 120 where the injection plan for the target well or wells continues and the tubing analysis continues at step 106 or, if the injection plan is completed, the job is ended and the next stages of the well life are performed.

Although the optimization methods are briefly shown above, the following sections provide a more detailed description of each of the stages.

Monitoring of reflection of tube waves in the wellbore

Methods in accordance with the invention include real-time monitoring of tubular wave reflections occurring in the wellbore to determine the depth and number of open fractures capable of receiving treatment fluid. In some embodiments, echo tube wave monitoring is performed by one or more distributed pressure sensors located in the wellbore.

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In FIG. 2 shows determination of fracture state using tube wave analysis for an idealized cased wellbore 202 treated with multi-stage fracturing. Tube wave analysis is performed by modeling the flow of slurry into the wellbore and calculating the distribution of its flow rate between one or more fractures. Petrophysical models can be used to calculate fracture parameters by inputting data measured from tube wave reflections inside the wellbore and using known physical relationships between geological properties, flow rates, injected fluid composition, and expected pressure changes to provide information on the location, number, length and fracture permeability within the specified wellbore interval. Petrophysical models that can be used to perform tube wave analysis include those presented in US Pat. No. 9,658,357 and the like. The measurement method includes determining the location of microseismic events, providing low-frequency pressure waves (tube waves) near the wellbore, registering pipe wave reflections from fractures in real time, and analyzing the locations of microseismic events and pipe wave reflections from fractures. US Pat. No. 9,103,203 describes the use of tube waves (acoustic disturbance) to evaluate the properties of a fluid-filled wellbore system. This is done by recording data, including at least one pressure and flow rate at one or more locations in the wellbore system, and then calculating the property value with a model to predict at least one pressure and flow rate depending on the characteristics and locations of fluctuations. pressure and flow rate in the wellbore system to determine the optimal prediction of any attribute of the logged data.

During tube wave analysis, pulse source 204 generates a pressure pulse s(t) as a continuous function of time t that traverses a wellbore containing several fractures 206. the pressure impulse s(t) generates a tube wave that propagates along the wellbore at a tube wave velocity V _TW . The distribution of tube wave velocities in the wellbore is generally unknown and depends on a number of wellbore specific factors, including wellbore geometry, formation elastic properties, elastic properties and the density of any fluids present.

Each time the tube wave impulse reaches the fracture 206, some of it is reflected and some propagates through the fracture. The wellhead pressure can be obtained as a discrete signal x(n) by a surface pressure gauge, where n is the sample volume. Analysis of the pressure signal on the surface x(n) makes it possible to determine the values of the depth of open cracks. In FIG. 2 specifically shows an example of the change in momentum at measured depth as a function of time. Analysis techniques can be used to narrow peaks within the data (a process known as deconvolution) and correct for variance (such as Q-filtering) to help identify cracks and other distortions. Peaks 208 correlate with wellbore reflectors, in this case fractures, at depths D1 and _D2 relative to surface 210.

In the next step, a convolution model is provided to record the discrete pressure fluctuation x(n). In FIG. 3 specifically shows that the x(n) model shown in FIG. 3, 302, is represented as a convolution of the source impulse s(t) 304 and the well impulse response w(n) 306. well impulse response w(n). Well impulse response w(n) is an unknown parameter in the convolution equation x(n) = s(n)*w(n). The well impulse response w(n) is a decaying minimum-phase sequence of pulses delayed by the arrival time, while their amplitudes depend on the respective reflection coefficients and on the attenuation of the wave in the wellbore. Reflection coefficients are determined from changes in resistance at the reflection boundaries. The reflection coefficients are negative for hydraulic fractures and positive for wellbore restrictions.

In one or more embodiments, the convolution equation may be solved by a deconvolution operation in the time domain or spectral division in the frequency domain. The depth values and types of the respective downhole reflectors are determined from the calculated impulse response of the well and the distribution of tubular wave velocities along the wellbore.

Combination of tube wave analysis with real-time multi-stage hydraulic fracturing simulator

In one or more embodiments, the methods may analyze tubular wave measurements in the wellbore using a combination of a flow split simulator and a multistage hydraulic fracturing simulator to determine the parameters of the fracturing treatment being performed. By using multiple measurements during a fracturing treatment, workflow can be modified to account for issues identified by flow-sharing models and multi-stage hydraulic fracturing models. Thus, the application of corrective measures can be avoided or minimized and maximum hydrocarbon recovery can be achieved.

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Flow Distribution Calculation Using Flow Sharing Model

In the methods used in accordance with the invention, a flow separation model can be used to determine the flow distribution for the flow entering the multi-stage fracture network. In FIG. 4 shows the theoretical basis of multistage hydraulic fracturing treatment. Cracks in the rock are formed near the perforation intervals. The positions and the total number of open cracks n are determined by tube wave monitoring. Each fracture grows depending on the flow rate of the fluid injected into it and the properties of the reservoir around it. The total injection rate Q is divided into n fractures. To pump the suspension into the formation from the surface, pressure P _ref is applied.

In one or more embodiments, flow distribution algorithms take into account a number of effects including: (1) casing friction, (2) hydrostatic forces, (3) pressure drop across perforations, and (4) presence of fractures. In some embodiments, any other sources of pressure drop may be added.

The casing friction in the wellbore, ΔP _frict , is given by Equation 1, where c is the friction pressure loss factor, Q is the wellbore flow, d is the friction pressure constant, and ΔL is the length of the wellbore element.

(1)

The hydrostatic pressure drop ΔP _hydrIi is given by Equation 2, where p _slurry is the density of the slurry used for treatment, g is the free fall acceleration, Δz _i is the height difference between the reference point A and the i-th perforation interval.

(2)

The pressure drop across the perforations is given by equation 3, where qi is the flow in the i-th perforation interval, mi is the number of perforations in the i-th interval, d _perf is the diameter of the perforations, and Cd is the perforation ratio (0.56 for the original shape, 0.89 for the final shape).

QiptAuny

ΔΡ^ _Γί , - 0.81 _? ., _r? ¹ ' (3)

The algorithm relates the Perkins-Kern-Nordgren (PKN) analytical model for a fracture with constant height to a set of equations describing the conservation of slurry volume and pressure constancy. These equations provide communication between multiple fractures through the wellbore. The effective pressure ΔP _ne t _Ii corresponds to the fracture PKN for the case of zero reservoir leakages, as shown in equation 4, where v is Poisson's ratio, μ is the fluid viscosity, E is Young's modulus, h is the fracture height, q _frac is the fluid flow in the fracture half-wing , as shown in Equation 5.

and t) (4)

-A (/frac ² (5)

Although the above example uses a multi-stage hydraulic fracturing simulator based on the PKN fracture model, it is envisaged that other multi-stage hydraulic fracturing simulators can be used to simulate the effective pressure created by the presence of a fracture, based on fracture models such as Khristianovich - Girtsma - de Klerk (KGD), radial model, pseudo-3D model, planar 3D model, full 3D model, etc.

The assumption in this algorithm is that there is no fluid transfer between fractures within the reservoir. This assumption implies that fractures communicate through the wellbore. Conserving the volume of the liquid gives the equation presented in Equation 6.

Q=\ ^nh *(6)

Pressure constancy implies that the sum of all pressure changes is equal to the control pressure for any path connecting the tip of the i-th fracture to the reference point A in FIG. 4, where Pclosure, i - fracture closure pressure in layer i.

p \u003d U ' ar + AR AR + AR + R ί-] n 'ref Z fri.-ti ^c % erG. ''hvrb. , W>et. /' (7)

The solution of the system of nonlinear equations (5)-(6), where q1, ..., q _n , P _ref are unknown quantities, is found by Newton's method for a nonlinear system of equations.

The flow separation model is used to calculate the flow rate distribution for each fracture attached to the wellbore and then further analyzed by the MSHF simulator during the implementation of the method. In one or more embodiments, the flow distribution between multiple fractures is calculated by simulating slurry flow into the wellbore during real-time evaluation of fracture geometry parameters.

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Fracture Simulator Calibration with Measured Operation-Related Data

After creating a model based on the MSHF simulator, the calculated values of q ₁ , ..., q _n and control pressure P _ref are compared with the measured data related to the hydraulic fracturing operation. If the calculated data values differ from the measured data (which is often expressed as a percentage), the parameters related to the operation are changed until there is a match between the simulated data and the received data.

Depending on the difference between the simulated results and the measured results, the multistage hydraulic fracturing simulator can be adjusted until the number of open fractures, injection rates, and fracture geometry parameters match the specified percentage error margin compared to the real-time estimate of the fracture geometry parameters obtained from the pipe analysis. waves. For example, the method may include adjusting the multistage hydraulic fracturing in cases where the error between the simulated results and the measured results from the tubular wave analysis exceeds 10%. In one or more embodiments, the specified percentage margin of error may be a percentage selected from 5%, 10%, 15%, and 20%. However, depending on the application, the percentage error margin may be greater or less than the indicated values.

Work analysis in real time

After using the multistage fracturing simulator incorporating the measurements to quantify the progress of the job, the selected fracturing job evaluation criterion can be used to analyze the variation between the original job design and the measurement-based job design. The criterion for evaluating hydraulic fracturing performance may include the number of fractures, fracture length, proppant placement, fracture permeability, etc., and combinations thereof.

In one or more embodiments, an arbitrary margin of variation may be set for the selected performance evaluation criterion so that the user can understand whether refinement of the work design is required before proceeding with the multi-stage fracturing treatment of the formation. In one or more embodiments, the margin of variation in the fracture performance evaluation criterion between the data values of the original work design and the measurement-based work design may be within a percentage selected from 1%, 5%, 10%, 15%, and 20%, with variation greater than the selected limit indicates the need to refine the original work plan to account for the differences noted in the measurement-based work plan. However, depending on the application, the percentage variation may be greater or less than the indicated values.

Refinement of the work project in real time

In the event that the measured results of a hydraulic fracturing job do not meet the criteria set in the original work plan, one or more methods may be used to refine the current work plan and ensure that the criteria are met. In one or more embodiments, the refinement of the work design may include real-time optimization of the work design by means such as changing one or more injection rates, proppant concentration, proppant type, proppant size, solids additives, fluid type, fluid additives, etc.

Applications

In one or more embodiments, fracturing techniques may be applied to a potential wellbore that has not previously been fractured. In some embodiments, the methods may include re-fracturing applied to wellbores that have previously been fractured to produce stimulated clusters and/or adding new perforations and fractures to a well that has previously been fractured.

System design

In one or more embodiments, the methods of the invention include a wellbore tube wave monitoring data collection system to determine the size and/or location of one or more existing wells. Data acquisition systems in accordance with the invention may include a pulse source capable of providing tubular waves within the wellbore, recorded by one or more sensors distributed at different depths within the wellbore. In one or more embodiments, the sensors may have a single configuration, or they may be combined into a group of distributed sensors to monitor reflected tube waves in a wellbore. Methods for recording pressure changes in the wellbore and equipment configuration are described, for example, in US patent No. 9476760.

The sensors according to the invention can detect and record pressure, vibration and/or flow. The sensors may include any number and any type of sensors suitable for downhole determination of pressure and vibration changes, such as quartz pressure gauges, optical sensors, including fiber optics, and the like. In one or more embodiments, the sensors may include commercially available WellWatcher® series sensors from Schlumberger Technology.

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Corporation.

Computing system

Systems in accordance with the invention are also configured to control a computer system that organizes the system for user or offline operation with multi-stage fracture evaluation in a subterranean formation. In one or more embodiments, the methods may use a multi-stage hydraulic fracturing simulator that determines flow sharing between multiple fractures, simulates the growth of hydraulic fractures in formation layers, and determines various fracture parameters. In addition to recommending corrective actions, if needed, once the operation is designed, real-time simulations can be used to calibrate the operation-related parameters.

Any combination of mobile, desktop, server, embedded, or other types of hardware can be used. For example, as shown in FIG. 5, the computing system (500) may include one or more computer processors (502), an associated storage device (504) (e.g., random access memory (RAM), fast buffer memory, flash memory, etc.), one or more storage devices (506) (eg, a hard disk drive, an optical drive, such as a compact disc (CD) or digital versatile disk (DVD) drive, flash memory card, etc.) and numerous other items and functions. The processor(s) of the computer (502) may be an integrated network for processing instructions. For example, the processor(s) of a computer may be a processor(s) with one or more cores or microkernels configured to perform the methods described above, including generating a fracturing job design, issuing instructions to execute a portion of the fracturing treatment of the formation, characterizing the degree of fracture propagation in the subterranean formation by monitoring the reflection of tube waves in the wellbore, determining the degree of fracture propagation to the original work plan and issuing commands to perform one of the changes to the original work plan and repeating the previous stages until the degree crack propagation will not be consistent with the original work design; or completion of the formation treatment by hydraulic fracturing. In addition, as can be understood from the invention, the characterization of the degree of propagation of hydraulic fracture may include the use of a pulse source to provide one or more tubular waves in the wellbore; measuring one or more pipe wave reflections in the wellbore; and determining at least one location or fracture width for the one or more fractures within the subterranean formation.

The computing system (500) may also include one or more input devices (510), such as a touch screen, keyboard, mouse, microphone, touch pad, electronic pen, or other form of input device. In addition, the computing system (500) may include one or more output devices (508) such as a screen (e.g., liquid crystal display (LCD), plasma display, touch screen, cathode ray tube (CRT) monitor, projector, or display device), printer, external storage device, or any other output device. One or more output devices may be input devices at the same time or may be separate devices. The computing system (500) may be connected to a network (512) (eg, a local area network (LAN), a wide area network (WAN) such as the Internet, mobile networks, or other types of networks) via a network interface (not shown). The input and output device(s) may be locally or remotely (e.g., via a network (512)) connected to the computer processor(s) (502), storage device(s) (504), and storage device(s) (506). . There are many different kinds of computing systems, and the above input and output devices can be represented in other forms.

Software instructions in the form of computer-readable source code for implementing embodiments of the invention may be stored, in whole or in part, temporarily or permanently, on a non-volatile computer-readable medium such as a compact disc, digital versatile disk, storage device, floppy disk, tape, flash memory , physical memory, or any other machine-readable storage medium. In particular, the software instructions may correspond to computer-readable source code that, when processed by the processor(s), is configured to implement embodiments of the invention. In addition, one or more elements of the above computing system (500) may be located in a remote location and connected to other elements via a network (512).

Furthermore, embodiments of the invention may be implemented in a distributed system with multiple nodes, with each part of the invention residing on a different node within the distributed system. In one embodiment of the invention, a node corresponds to a single computing device. Alternatively, a node may correspond to a computer processor with associated physical memory. Alternatively, a node may correspond to a computer processor or microkernel of a computer processor with shared memory and/or resources.

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Examples

The following examples show scenarios in which the methods of the invention are used to verify compliance with the original hydraulic fracturing design in real time as the work progresses.

Example 1 Placement of Proppant in Fractures

In this example, the method is applied to a job design that has an initial criterion for placing 100% proppant slurry in multiple artificial fractures. In FIG. 6 specifically shows that feature 602 represents an initial job design where three fractures 610 are artificially created and filled with proppant slurry in a selected wellbore interval 608. In the initial work design, the design criterion for a hydraulic fracture is the result that all fractures contain equal amounts of proppant. During the execution of the fracturing design, more fractures may be generated than planned, as shown by the four artificial fractures 612 of element 604. The formation of additional fractures indicates that the injection plan designed for fewer fractures will result in the injection of less fluid into fractures 612, in as a result, a small fracture width can be observed due to insufficient proppant placement and/or fracture tip shielding.

With particular reference to element 606, tubular wave analysis can be used during a fracturing job to detect inconsistencies in performance, such as the presence of unplanned additional fractures 614. Using the tubular wave analysis shown in element 606 in accordance with the invention, an operator can identify problems in in real time and take one of a number of possible corrective actions to increase the injection rate to avoid proppant loss from the fracturing fluid. Another possible corrective action is to inject diversion material to block the propagation of one fracture and continue stimulating the remaining fractures.

Example 2. Controlling the length of artificially formed cracks

In a further example, the methods of the invention are used to design a fracturing job so as to create fractures of a given length L or less in a wellbore interval in accordance with a fracturing job evaluation criterion. In FIG. 7 specifically shows that element 702 is an illustration of a work design in which three fractures 710 of length L are planned in a wellbore 708 (original work design). During the course of the work, as shown in element 704, one or more of the planned fractures 714 may not be formed (failed fracturing). In this case, more proppant slurry will enter the remaining wells 712, and the final fracture length will be greater than the planned length L. Uncontrolled fracture propagation can lead to a number of complications, including penetration into adjacent wells and the occurrence of unwanted well breaks (fractures from different wells coalescing).

Using the methods according to the invention, it is possible to prevent stimulated cracks from extending beyond the established limits by means of corrective actions and intervention, as shown in element 706. This becomes possible because the absence of intended cracks (in this case, two opened cracks instead of three opened cracks according to the work plan). For example, corrective action on element 706 may be to reduce the volume of proppant slurry as described by Equation 8, where V _initial is the initial volume of slurry to be injected into the well; n _frac , _initial - estimated number of cracks before the start of work; nfrac, _actual - the number of cracks according to the analysis of tube waves; V _ad j _usted is the corrected volume of suspension to be injected into the well.

v adjusted

And __ frac, actual ^r initial

And frac,initial(8)

As shown in element 706, real-time tubing analysis during fracturing operations may indicate that the fracture design should be modified (real-time) by reducing the injected amount to adjust the final fracture lengths 716 to match the L values set in original crack design.

Although several exemplary embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications to the exemplary embodiments are possible without substantially deviating from the present invention. Accordingly, all such modifications are intended to be included within the scope of the present invention as defined in the following claims. In the claims, the means plus function clauses represent structures that are presented herein as performing the described function, and not only as structural equivalents, but also as equivalent structures. Therefore, although a nail and a screw cannot be structural equivalents, since a nail uses a cylindrical surface to hold wood together, while a screw uses a helical surface, in a fastening medium

- 8 042125 wooden parts nail and screw can be equivalent structures.

Claims (10)

(1) selecting a wellbore for the multi-stage fracturing treatment, developing an initial multi-stage fracturing job design, determining one or more criteria for evaluating the fracturing job, and developing a tube wave propagation model in the wellbore based on the initial job design; 1. A method for treating an underground formation, comprising: 2. The method of claim 1, wherein the tube wave propagation model comprises a well impulse response parameter. (2) initiation of part of the initial work project; 3. The method of claim 1, wherein the criterion for evaluating hydraulic fracturing performance is the cumulative amount of proppant placed in all fractures. (3) providing one or more tube waves in the wellbore and monitoring one or more reflections of one or more tube waves and calculating the number of open fractures and fracture geometry parameters in accordance with the tube wave propagation model; 4. The method of claim 1, wherein the number of stimulated fractures in the multi-stage fracturing treatment of the formation differs from the original work design. (4) performing a real-time evaluation of fracture geometry parameters by calculating one or more flow rates while injecting into a series of open fractures and simulating the hydraulic fracturing process for a series of open fractures using a multi-stage hydraulic fracturing simulator; 5. The method of claim 1, wherein the criterion for evaluating hydraulic fracturing performance is the specific amount of proppant in each fracture. (5) adjusting the multi-stage fracturing simulator parameters until the number of open fractures, one or more injection rates, and fracture geometry parameters from step (3) match the real-time fracture geometry parameter estimate from step (4) , to provide an adjusted fracturing simulator; 6. The method of claim 1, wherein the tube wave propagation model determines the number of open fractures in the wellbore and one or more fracture geometry parameters selected from fracture depth, fracture length, width, height. (6) calculation of fracture geometry parameters using the corrected hydraulic fracturing simulator to develop a work design based on the measurement results; 7. The method of claim 1, wherein the reflected tube waves are monitored by a wellhead pressure sensor or one or more distributed wellbore pressure sensors. (7) calculating the difference between the fracturing evaluation criteria for the original work design and the work design based on the measurement results; and (8) doing one of the following: checking that the difference obtained in step (7) is below a prescribed variation for one or more of the fracturing job evaluation criteria, and proceeding with the original work plan; or refining the original work design and repeating steps (6) and (7) until the difference obtained in step (7) is below the prescribed variation for one or more of the fracturing job evaluation criteria, and continuing with the revised version of the original work project; and (9) repeating steps (3)-(8) until completion of the multi-stage fracturing treatment. 8. The method of claim 1, wherein the real-time estimation is performed by simulating the flow of slurry into the wellbore to calculate the flow distribution between multiple fractures. 9. The method of claim 1, wherein modeling the fracturing process for a number of open fractures using a multi-stage hydraulic fracturing simulator comprises estimating one or more fracture geometry parameters. 10. The method of claim 1, wherein adjusting the multi-stage fracturing simulator comprises adjusting one or more job parameters selected from injection flow, proppant concentration, proppant size, fiber additives, fluid type, and amount of fluid additives.