Shale gas well inter-well pressure channeling identification method, system, equipment and medium

Abstract

The invention provides a shale gas well inter-well pressure channeling identification method, system, device and medium, the shale gas well inter-well pressure channeling identification method comprises the following steps: carrying out well test analysis in a pump stop pressure drop stage after fracturing, and collecting data; the bottom hole pressure is calculated, and pressure data oscillation caused by the water hammer effect is eliminated; drawing a pressure difference and pressure difference derivative double logarithmic curve based on the bottom hole pressure data; establishing a shale gas well non-uniform fracture multi-zone coupling well test seepage model; the model parameters are adjusted, a pressure difference and pressure difference derivative double logarithmic curve is fitted, and when the model result is close to the drawn pressure difference and pressure difference derivative double logarithmic curve, the crack parameters of the model parameters are obtained through inversion; judging whether the crack parameter is too high or not; and determining the relationship between the child well group and the mother well group, analyzing the pressure difference and pressure difference derivative curve morphological characteristics of the fracture parameter high section, and judging whether pressure channeling occurs or not. The system can realize the method. According to the method, the inter-well pressure channeling identification efficiency in the well group synchronous fracturing period can be improved.

Description

Technical Field

[0001] This invention relates to the field of unconventional natural gas development technology, specifically to a method, system, equipment, and medium for identifying inter-well pressure channeling in shale gas wells. Background Technology

[0002] Horizontal well volumetric fracturing technology is a key means to achieve effective development of shale gas reservoirs. Obtaining post-fracturing fracture parameters is a prerequisite and guarantee for completing fracturing effect evaluation and fracturing process optimization. Currently, direct monitoring methods, represented by microseismic monitoring, are generally costly and difficult to implement one-well-one-testing; indirect evaluation forward modeling methods, represented by fracturing simulation, require many basic parameters and have high data quality requirements; while traditional pressure drop / recovery well test analysis methods require long-term shut-in testing and the interpretation results are vague. At the same time, due to the continuous increase in shale gas infill wells and the decrease in well spacing, inter-well pressure channeling problems have become prominent, seriously affecting gas well productivity. It is necessary to identify inter-well pressure channeling in a timely manner to provide effective guidance for fracturing operations. Existing pressure channeling identification mainly uses production data and pressure changes from adjacent wells for identification, which has poor identification accuracy and cannot diagnose pressure channeling during synchronous fracturing of well groups. There is an urgent need to propose an efficient and applicable method for identifying shale gas well pressure channeling. Therefore, providing a method, system, equipment, and medium for identifying inter-well pressure channeling in shale gas wells is of great significance.

[0003] Chinese patent application number CN202110133390.X, entitled "A Method for Identifying Fracture Communication in a Fracturing Horizontal Well," discloses a method for identifying fracture communication in a fracturing horizontal well. This method includes the following steps: using a segmented injection tubing assembly to inject into all fracturing sections of the horizontal well under test, simultaneously acquiring the injection pressure and injection rate for each section; plotting the injection pressure and injection rate variation curves for each section, and determining whether fracture communication exists in each section based on these curves. This method uses the variation patterns of injection rate and pressure during the injection process to concisely identify fracture communication, is simple to operate, has a short identification time, and can easily identify formation fracture connectivity. However, this method differs from the method in this application. Summary of the Invention

[0004] The purpose of this invention is to address at least one of the aforementioned shortcomings of the existing technology. For example, one objective of this invention is to provide a method for identifying inter-well pressure channeling in shale gas wells that is suitable for shale gas reservoirs, requires no shut-in pressure testing, is highly efficient, provides detailed interpretation results, and allows for easy acquisition of basic parameters. Another objective of this invention is to provide a shale gas well inter-well pressure channeling identification system that offers good identification performance, can diagnose pressure channeling during synchronous fracturing of well groups, and allows for timely identification.

[0005] To achieve the above objectives, this invention provides a method for identifying inter-well pressure channeling in shale gas wells. The method includes: conducting well test analysis during the pressure drop phase after pump shutdown following fracturing, collecting fracturing operation data, reservoir parameters, fluid property parameters, and well completion data; calculating the bottom hole pressure and eliminating pressure data oscillations caused by water hammer; plotting a double logarithmic curve of pressure differential and its derivative based on the bottom hole pressure data; establishing a multi-zone coupled well test flow model of non-uniform fractures in a shale gas well; adjusting the input model parameters based on the established multi-zone coupled well test flow model of non-uniform fractures in a shale gas well, fitting the double logarithmic curve of pressure differential and its derivative; when the model calculation result curve is close to the double logarithmic curve of pressure differential and its derivative plotted based on the bottom hole pressure data, the fracture parameters in the input model parameters are the fracture parameters obtained through inversion; determining whether the fracture parameters obtained through inversion are too high; if too high, determining the relationship between the parent and child well groups and analyzing the morphological characteristics of the pressure differential and its derivative curves in the high fracture parameter segment to determine whether pressure channeling has occurred.

[0006] According to an exemplary embodiment of one aspect of the present invention, the fracturing construction data, reservoir parameters, fluid property parameters and well completion data may include: fracturing construction pump pressure data, pump injection rate, gas property parameters, formation original pressure, formation temperature, comprehensive compressibility coefficient, permeability, porosity, fracturing fluid viscosity and density, well perforation location coordinates, number of clusters in a single section, cluster spacing, fracturing section depth and wellbore trajectory coordinates.

[0007] According to an exemplary embodiment of one aspect of the present invention, the calculation of bottom hole pressure may include:

[0008] p B =p h +ρ f gZ w Formula 1

[0009] Where, p B The bottom hole pressure is in MPa; p h ρ is the wellhead pump pressure, MPa; f The density of the fracturing fluid is kg / m³. 3 Z w ρ is the vertical depth of the fracturing section, in km; g is the acceleration due to gravity, in m / s². 2 .

[0010] According to an exemplary embodiment of one aspect of the present invention, eliminating pressure data oscillations caused by water hammer may include: using Gaussian filtering to perform noise reduction processing on pressure data oscillations caused by water hammer after rapid pump shutdown.

[0011] According to an exemplary embodiment of one aspect of the present invention, based on the bottom hole pressure after oscillation elimination, a double logarithmic curve of pressure difference and its derivative is plotted. The formulas for calculating the pressure difference and its derivative are as follows:

[0012]

[0013] Where, Δp i p is the pressure difference at the i-th time step; i p1 is the pressure at the i-th time step, MPa; p1 is the initial pressure at the time step, MPa; Δp i ' is the derivative of the pressure difference at the i-th time step, MPa; Δp1 is the initial time pressure difference, MPa; Δt i The time difference between the i-th time step and the initial time; t i Let i be the time.

[0014] According to an exemplary embodiment of one aspect of the present invention, the multi-zone coupled well test seepage model of the shale gas well with non-uniform fractures can be:

[0015]

[0016] in, The dimensionless pseudo-pressure is used for the microcracks in the outer region. The outer matrix is ​​dimensionless pseudo-pressure; The internal microcracks are dimensionless pseudo-pressures. ω1 represents the dimensionless pseudo-pressure of the inner zone matrix; s is a Laplace variable, dimensionless; ω1 is the outer zone reservoir ratio, dimensionless; ω2 is the inner zone reservoir ratio, dimensionless; q Di,j Let x be the dimensionless linear density flow rate of the j-th segment of the hydraulic fracture in the i-th inner zone of the pull-type space; Г1 is the outer zone boundary; Г2 is the inner zone boundary; x D y D η is a dimensionless unit of length; η is the ratio of the pressure conductivity coefficient of the outer region to that of the inner region; W i S represents the number of discrete hydraulic fractures in the inner zone; Di,j For the i-th inner zone, the j-th hydraulic fracture segment has a dimensionless length; δ() is the Dirac function; x i,j ,y i,j For the i-th inner zone, the location of the j-th hydraulic fracture; t D denoted as dimensionless time; n is the direction of the boundary normal vector; M is the ratio of permeability between the outer and inner zones; x and y are the positioning coordinates in the rectangular coordinate system; j refers to the j-th segment of the hydraulic fracture; the inner zone is the complex fracture network area generated by the fracturing operation; the outer zone is the area unaffected by the fracturing operation.

[0017] According to an exemplary embodiment of one aspect of the present invention, the step of determining whether the crack parameters obtained by inversion are too high may include: determining whether the average crack half length and the total crack length of a single segment of the kth segment are higher than those of the adjacent segments; if so, the kth segment is a segment with high crack parameters.

[0018] According to an exemplary embodiment of one aspect of the present invention, determining the relationship between the parent and daughter well groups and analyzing the morphological characteristics of the differential pressure and differential pressure derivative curves in the high-parameter section of the fracture may include: if the parent well is a well that has been put into production after fracturing and the daughter well is a fracturing well, comparing the high-parameter section of the fracture with the double logarithmic curves of differential pressure and differential pressure derivatives of two adjacent sections, if the differential pressure of the high-parameter section of the fracture is greater than that of the two adjacent sections during the wellbore storage stage, and the differential pressure derivative of the high-parameter section of the fracture is less than that of the two adjacent sections during the linear flow stage, then the high-parameter section of the fracture is a pressure channeling section; if the parent well is a well that has not been put into production after fracturing and the daughter well is a fracturing well, if the differential pressure derivative curve of the high-parameter section of the fracture has a slope of -1 / 2 during the transition stage, and the bottom hole pressure is less than that of the parent well, then the high-parameter section of the fracture is a pressure channeling section.

[0019] Another aspect of the present invention provides a shale gas well inter-well pressure channeling identification system. The system may include a data collection unit, a bottom-hole pressure calculation unit, a curve plotting unit, a well test flow model unit, an inversion unit, a judgment unit, and a discrimination unit. The data collection unit, bottom-hole pressure calculation unit, and curve plotting unit are connected sequentially; the inversion unit is connected to the well test flow model unit and the curve plotting unit; the inversion unit, judgment unit, and discrimination unit are connected sequentially; and the judgment unit is connected to the well test flow model unit. The data collection unit is configured to conduct well test analysis during the pressure drop phase after pump shutdown following fracturing, collecting fracturing operation data, reservoir parameters, fluid property parameters, and well completion data. The bottom-hole pressure calculation unit is configured to calculate the bottom-hole pressure and eliminate pressure data oscillations caused by water hammer effects. The line plotting unit is configured to plot double logarithmic curves of differential pressure and differential pressure derivative based on bottom hole pressure data; the well test seepage model unit is configured to establish a multi-zone coupled well test seepage model of non-uniform fractures in shale gas wells; the inversion unit is configured to adjust the input model parameters and fit double logarithmic curves of differential pressure and differential pressure derivative based on the established multi-zone coupled well test seepage model of non-uniform fractures in shale gas wells. When the model calculation result curve is close to the double logarithmic curves of differential pressure and differential pressure derivative in the curve plotting unit, the fracture parameters in the input model parameters are the fracture parameters obtained by inversion; the judgment unit is configured to judge whether the fracture parameters obtained by the inversion unit are too high; the discrimination unit is configured to determine the relationship between the parent and child well groups and analyze the morphological characteristics of the differential pressure and differential pressure derivative curves in the section with high fracture parameters to determine whether there is pressure channeling.

[0020] Another aspect of the present invention provides a computer device, the device comprising: a processor; and a memory storing a computer program, wherein when the computer program is executed by the processor, the method for identifying inter-well pressure crosstalk in shale gas wells as described in any of the preceding claims can be implemented.

[0021] Another aspect of the present invention provides a computer-readable storage medium storing a computer program that, when executed by a processor, can implement the shale gas well inter-well pressure crosstalk identification method described in any of the above claims.

[0022] Compared with the prior art, the beneficial effects of the present invention include at least one of the following:

[0023] (1) The shale gas well inter-well pressure channeling identification method proposed in this invention can directly use the delayed pressure measurement data of the pump shutdown stage after fracturing to carry out well test analysis. Compared with traditional well test analysis, it does not require long-term shut-in testing and can interpret single-segment fracture parameters.

[0024] (2) The shale gas well inter-well pressure channeling identification method proposed in this invention can use digital filtering to reduce noise in the measured data, overcoming the problem of pressure data oscillation and obvious curve morphology fluctuation caused by the water hammer effect caused by rapid pump shutdown.

[0025] (3) The shale gas well inter-well pressure channeling identification method proposed in this invention can invert fracture parameters by constructing a multi-zone coupled well test model of non-uniform fractures in shale gas wells, and interpret the parameters of a single fracture segment by inverting them. By combining the morphological characteristics of the double logarithmic curve of the pump stop pressure drop test and the inversion results of fracture parameters, it can not only diagnose inter-well pressure channeling between fractured wells and production wells, but also effectively identify inter-well pressure channeling between fractured wells on the same platform.

[0026] (4) The shale gas well inter-well pressure channeling identification system proposed in this invention can identify inter-well pressure channeling in a timely manner, providing effective guidance for fracturing operations. Attached Figure Description

[0027] The above and other objects and features of the present invention will become clearer from the following description taken in conjunction with the accompanying drawings, in which:

[0028] Figure 1 A flowchart illustrating an exemplary embodiment of the shale gas well inter-well pressure channeling identification method of the present invention is shown.

[0029] Figure 2A The typical differential pressure and differential pressure derivative double logarithmic curves are shown for the pressure drop before pump shutdown before noise reduction;

[0030] Figure 2B The typical differential pressure and differential pressure derivative double logarithmic curves are shown for the pressure drop after pump shutdown after noise reduction;

[0031] Figure 3 A schematic diagram of the fitting of measured data is shown;

[0032] Figure 4A A comparison chart of average crack half-lengths is shown, illustrating the comparison of crack parameter inversion results.

[0033] Figure 4B This diagram shows a comparison of the total length of a single crack segment in the crack parameter inversion results.

[0034] Figure 5A comparison chart of the pressure difference and pressure difference derivative curves between the section with higher crack parameters and the adjacent section is shown.

[0035] Figure 6 The pressure derivative curves for the high-parameter crack segments are shown.

[0036] Figure 7 A schematic diagram of the structure of a shale gas well inter-well pressure channeling identification system according to an exemplary embodiment of the present invention is shown;

[0037] Figure 8 A schematic diagram of the physical model is shown;

[0038] Figure 9A The diagram shows the boundary discretization and integration order outside the boundary discretization and integration order.

[0039] Figure 9B The diagram shows the boundary discretization and integration order within the inner region. Detailed Implementation

[0040] In the following, a method, system, device, and medium for identifying inter-well pressure channeling in shale gas wells according to the present invention will be described in detail with reference to the accompanying drawings and exemplary embodiments.

[0041] In the description of this application, it should be understood that the terms "S1 to S7" etc. are used to distinguish similar objects and are not necessarily used to describe a specific order or sequence.

[0042] Exemplary Example 1

[0043] This exemplary embodiment provides a method for identifying inter-well pressure channeling in shale gas wells.

[0044] The method for identifying inter-well pressure channeling in shale gas wells can be summarized as follows: First, preprocess the pump shutdown pressure drop data, converting the wellhead pump pressure into bottom hole pressure, and use Gaussian filtering to reduce noise in the data, obtaining a double logarithmic curve for well test analysis; then, based on the established unsteady flow model, adjust the model parameters to fit the well test double logarithmic curve as closely as possible to obtain single-segment fracture parameters; finally, based on the relationship between different well groups and the morphological characteristics of the pump shutdown pressure drop double logarithmic curve of the pressure channeling segment, identify the inter-well pressure channeling segment.

[0045] like Figure 1As shown, the method for identifying inter-well pressure channeling in shale gas wells mainly includes: preprocessing pump shutdown pressure drop data, statistically analyzing fracturing operation data, and collecting pump shutdown pressure drop data; obtaining pump pressure-time data based on the pump shutdown pressure drop data, and obtaining well depth and fracturing section depth based on the fracturing operation data; calculating bottom hole pressure based on pump pressure-time data, well depth, and fracturing section depth, and performing Gaussian filtering to reduce noise in the bottom hole pressure; and obtaining a double logarithmic curve for well test analysis. Well test analysis was conducted during the pump shutdown pressure drop phase to obtain reservoir and fluid properties and an unsteady flow model. Based on the established multi-zone coupled well test flow model of non-uniform fractures in shale gas wells, reservoir, fluid properties, and fracture parameters were input to obtain model calculation results. These parameters were then adjusted to fit the double logarithmic curve plotted from measured data as closely as possible. The ideality of the fitting result was assessed (if the model calculation curve closely matches the double logarithmic curve of the measured data, the fitting result is ideal; otherwise, it is not ideal). When the fitting effect is ideal, the input fracture parameters are the final fracture parameters obtained through inversion. If the fitting effect is not ideal, the model parameters are adjusted, and the fracture parameters are re-obtained. The suitability of the obtained fracture parameters is then assessed. Significantly higher than other segments (adjacent segments), specifically, the average fracture half-length and the total fracture length of a single segment are compared. If both are significantly higher, then the segment has high fracture parameters. If the obtained fracture parameters are determined to be significantly higher than other segments, then a double logarithmic curve morphology analysis of the pressure drop after pump shutdown is performed. The relationship between the parent and daughter well groups is determined. If the parent well is fracturing first and then put into production, and the daughter well is fracturing, and the pressure curve (i.e., differential pressure curve) of the daughter wellbore reservoir stage is high, and the pressure derivative curve of the transition stage is low, then the segment with high fracture parameters can be identified as a pressure channeling segment. If the parent well is fracturing first but not put into production, and the daughter well is fracturing, and the slope of the pressure derivative in the transition stage of the daughter well has a -1 / 2 characteristic, and the bottom hole pressure is less than that of the parent well, then the segment with high fracture parameters can be identified as a pressure channeling segment. Here, it should be noted that the models mentioned all refer to the shale gas non-uniform fracture multi-zone coupled well test seepage model.

[0046] Specifically, the shale gas well inter-well pressure channeling identification method of this exemplary embodiment may include the following steps:

[0047] S1. Conduct well test analysis and collect data during the pressure drop phase after pump shutdown following fracturing.

[0048] Specifically, well test analysis is conducted during the pump shutdown pressure drop phase after fracturing. Pressure drop data during the shutdown phase can be obtained based on the actual fracturing operation pump-pressure curve. Delayed pressure measurement data from the pump shutdown phase after fracturing is used as part of the measured data for well test analysis. This includes collecting fracturing operation data, reservoir and fluid properties, and well completion data. Here, pressure measurement data refers to pump pressure-time data; other data are used to calculate the bottom hole pressure from the pressure measurement data. The final calculated bottom hole pressure data is then used as the well test analysis data.

[0049] Here, the fracturing operation data, reservoir parameters, fluid properties parameters, and completion data in S1 can specifically include: fracturing operation pump pressure data (including wellhead pump pressure), pump injection rate, gas properties parameters, original formation pressure, formation temperature, comprehensive compressibility coefficient, permeability, porosity, fracturing fluid viscosity and density, well perforation location coordinates, number of clusters per segment and cluster spacing, fracturing segment depth (i.e., vertical depth of the fracturing segment), and wellbore trajectory coordinates.

[0050] S2. Calculate the bottom hole pressure and eliminate pressure data oscillations caused by water hammer. Specifically, this includes:

[0051] S201. Calculate the bottom hole pressure. The bottom hole pressure is calculated based on pump pressure-time data and fracturing operation data, etc. The bottom hole pressure calculation is as follows:

[0052] p B =p h +ρ f gZ w Formula 1

[0053] Where, p B The bottom hole pressure is in MPa; p h ρ is the wellhead pump pressure, MPa; f The density of the fracturing fluid is kg / m³. 3 Z w ρ is the vertical depth of the fracturing section, in km; g is the acceleration due to gravity, in m / s². 2 .

[0054] S202. For the calculated bottom hole pressure, a preferred digital filtering method is to eliminate pressure data oscillations caused by water hammer effect, which may include: using Gaussian filtering to denoise the pressure data oscillations caused by water hammer effect after rapid pump shutdown.

[0055] from Figure 2A As can be seen, the pressure derivative curve before filtering and noise reduction exhibits irregular oscillations, which cannot meet the requirements for well test interpretation. Figure 2B As can be seen, the quality of the pressure derivative curve after filtering and noise reduction is significantly improved, which can meet the requirements of well test interpretation.

[0056] S3. Based on the denoised bottomhole pressure data, plot the double logarithmic curves of pressure differential and its derivative. Here, the double logarithmic curves are plotted using the denoised data as the curve to be fitted to the established model. This curve represents measured data, and fracture parameters will be obtained by fitting this curve subsequently. The formulas for calculating the pressure differential and its derivative are:

[0057]

[0058] Where, Δp i p is the pressure difference at the i-th time step; ip1 is the pressure at the i-th time step, MPa; p1 is the initial pressure at the time step, MPa; Δp i ' is the derivative of the pressure difference at the i-th time step, MPa; Δp1 is the initial time pressure difference, MPa; Δt i The time difference between the i-th time step and the initial time; t i Let Δt be time i. i =t i -t1, where t1 is the initial time.

[0059] S4. Establish a multi-zone coupled well test seepage model for non-uniform fractures in shale gas wells.

[0060] The non-uniform fracture multi-zone coupled well test seepage model for shale gas wells is as follows:

[0061]

[0062] in, The dimensionless pseudo-pressure is used for the microcracks in the outer region. The outer matrix is ​​dimensionless pseudo-pressure; The internal microcracks are dimensionless pseudo-pressures. ω1 represents the dimensionless pseudo-pressure of the inner zone matrix; s is a Laplace variable, dimensionless; ω1 is the outer zone reservoir ratio, dimensionless; ω2 is the inner zone reservoir ratio, dimensionless; q Di,j Let x be the dimensionless linear density flow rate of the j-th segment of the hydraulic fracture in the i-th inner zone of the pull-type space; Г1 is the outer zone boundary; Г2 is the inner zone boundary; x D y D η is a dimensionless unit of length; η is the ratio of the pressure conductivity coefficient of the outer region to that of the inner region; W i S represents the number of discrete hydraulic fractures in the inner zone; Di,j For the i-th inner zone, the j-th hydraulic fracture segment has a dimensionless length; δ() is the Dirac function; x i,j ,y i,j For the i-th inner zone, the location of the j-th hydraulic fracture; t D denoted as dimensionless time; n is the direction of the boundary normal vector; M is the ratio of permeability in the outer zone to that in the inner zone; x and y are the location coordinates in a rectangular coordinate system; j refers to the j-th hydraulic fracture segment. After hydraulic fracturing, a complex fracture network region is generated near the fracturing operation section in a horizontal well. This complex fracture network makes it easier for reservoir fluids to flow into the wellbore. Therefore, we refer to the complex fracture network region generated by the fracturing operation as the inner zone, while the region unaffected by the fracturing operation is called the outer zone.

[0063] The process of establishing a multi-zone coupled well test seepage model for non-uniform fractures in shale gas wells may include:

[0064] S401. Establish a physical model.

[0065] After horizontal well fracturing, the physical properties of the fracturing and unfracturing areas differ significantly. The model characterizes the fracturing and unfracturing areas separately. Figure 8 ), where Γ represents the region boundary, Ω represents the region, subscript 1 represents the outer region and outer boundary, and the remaining subscripts represent the inner region and inner boundary. Model assumptions: ① Single-phase gas flow within the reservoir; ② Consideration of finite conductivity and stress-sensitive effects of hydraulic fractures; ③ Neglect of the effects of gravity and capillary forces.

[0066] S402. Establish a mathematical model.

[0067] Dimensionlessness:

[0068] The subscript 2 will be used to represent the inner area and the inner area boundary.

[0069] Dimensionless distance:

[0070]

[0071] Dimensionless pressure, flow rate, and time:

[0072]

[0073] Dimensionless permeability modulus and fracture conductivity:

[0074]

[0075] Dimensionless well reservoir coefficient:

[0076]

[0077] Other parameter definitions:

[0078]

[0079] Using the point source function method, by introducing pseudo-pressure, dimensionless variables, and Laplace variation, we can obtain the control equations for the inner and outer zones, as well as the crossflow equation (subscript 2 uniformly represents the inner zone and inner boundary):

[0080] The control equations for seepage in the outer zone are as follows:

[0081]

[0082] The control equations for seepage in the inner zone are as follows:

[0083]

[0084] Formula for crosstalk term:

[0085]

[0086] Initial conditions:

[0087]

[0088] External boundary conditions:

[0089]

[0090] Conditions for the connection between inner and outer zones:

[0091]

[0092] The fundamental solutions of equations 4 and 5 in Laplace space using the boundary element method are:

[0093]

[0094] Where P and Q represent any point within the domain or on the boundary.

[0095] The outer boundary Γ1 of the reservoir can be discretized into N1 line segments, and the inner boundary Γ2…Γ n+1 It can be discretized into N2…N n+1 The line segments, their boundary discrete point numbers, and the order of integration in the outer region are as follows: Figure 9A As shown, the order of integration in the inner region is as follows: Figure 9B As shown.

[0096] Based on the boundary element method, the boundary integral equation for any point k in the outer region of the Laplace space is:

[0097]

[0098] Similarly, the boundary integral equation for any point k in the inner region is:

[0099]

[0100] Among them, Q k P is any point within the domain or on the boundary; P′ is any point on the boundary; W i Let θ be the number of discrete hydraulic fracture segments in the i-th inner zone; θ is related to Q. k Constants related to the geometry at a point,

[0101] β is Q k The angle between the discrete segments of the left and right boundaries at the point.

[0102] Similarly, the boundary integral equation for the center point of the discrete crack segment in the inner region is:

[0103]

[0104] Wherein, the subscript F represents a hydraulic fracture, and Q F This represents the midpoint of the discrete segment of the hydraulic fracture in the inner zone.

[0105] Considering the stress sensitivity of hydraulic fractures, the fracture control equation is obtained by using exponential permeability variation:

[0106]

[0107] By using Pedrosa variable substitution and perturbation transformation, combined with Equation 14, we get:

[0108]

[0109] Where ψ FD Satisfy the following formula:

[0110]

[0111] In Laplace space, the crack model can be discretized to obtain:

[0112]

[0113] Where R FD The dimensionless conductivity coefficient of the hydraulic fracture can be set to different values ​​for each fracture when analyzing specific problems, in order to characterize the difference in conductivity of different hydraulic fractures in the same horizontal well caused by differentiated fracturing operations.

[0114] The production conditions for horizontal wells are expressed as follows:

[0115]

[0116] At this time, the model has a total of Given a set of unknowns, we establish a corresponding number of equations using the listed equations, and then construct a coefficient matrix to solve the problem.

[0117] When considering wellbore reservoir effect and skin effect, based on the solution We can obtain:

[0118]

[0119] Finally, the Stehfest numerical inversion algorithm is used to obtain ψ in real space. wD The pseudo-pressure m at the bottom of the well, considering the stress sensitivity effect of hydraulic fractures, is obtained through Equation 16. wD .

[0120] The main parameters of the above expression are explained as follows:

[0121] x F The hydraulic fracture half-length is in meters (m); S i,j For the i-th inner zone, the length of the j-th hydraulic fracture segment is m; L i,jLet m be the distance from the horizontal well to the i-th inner zone and the j-th hydraulic fracture, in meters; m is the pseudo-pressure, in Pa·s. -1 k is the permeability, m 2 h is the reservoir thickness (m); T is the reservoir temperature (K); q is the production rate (m). 3 / s; p is pressure, Pa; t is time, s; μ gi φ is the initial viscosity of the fluid, Pa·s; φ is the porosity, dimensionless; c is the overall compressibility, Pa. -1 γ is the fracture permeability modulus, Pa·s / Pa 2 ;R FD The dimensionless conductivity of the hydraulic fracture; w F C is the width of the hydraulic fracture, in meters; C is the well-reservoir coefficient, in meters. 3 ·Pa; ω is the storage ratio, dimensionless; τ is the ratio of the pressure conductivity coefficient of the outer zone to that of the hydraulic fracture; λ is the crossflow coefficient, dimensionless; α is the matrix block shape factor, m -2 M is the ratio of permeability in the outer zone to that in the inner zone; η is the ratio of pressure conductivity in the outer zone to that in the inner zone; Γ is the region boundary; Ω is the region; s is the Laplace transform variable; W i The number of discrete segments of hydraulic fractures in the i-th inner zone; For the i-th inner zone under the pull-type space, the dimensionless linear density flow rate of the j-th hydraulic fracture segment; Let x be the dimensionless linear density flow rate of the nth hydraulic fracture segment in the i-th inner region of the Lagrange space; δ() is the Dirac function; i,j ,y i,j The location of the hydraulic fracture in the j-th segment of the i-th inner zone; n is the boundary normal vector; K0() is the zero-order Bessel function; l n The dimensionless length of the nth boundary discrete segment; For the i-th inner region in the pull-type space, the j-th hydraulic fracture has dimensionless pseudo-pressure; S k ξ is the skin coefficient, dimensionless; E(P,Q,u) is the fundamental solution of the seepage control equation; ξ is the integral variable, meaningless in itself, and can be replaced by any symbol; ψ FD The hydraulic fracture pressure after Pedrosa variable substitution and perturbation transformation; ψ wD The bottom hole pressure after Pedrosa variable substitution and perturbation transformation; m i The initial pseudo-pressure of the formation, Pa·s -1 ;q sci,jLet represent the production of the j-th hydraulic fracture in the i-th inner zone under the bottom edge condition; x and y represent coordinate parameters in the rectangular coordinate system; superscript - indicates Laplace space; subscript m indicates matrix; subscript f indicates microfracture; subscript F indicates hydraulic fracture; subscript D indicates that the parameter is dimensionless; subscript 1 indicates outer zone; subscript 2 indicates inner zone; subscript sc indicates surface condition; subscript i indicates initial condition; subscript wD indicates bottom of well.

[0122] S5. By adjusting the well test model parameters and fitting the measured data (fitting the double logarithmic curves of differential pressure and differential pressure derivative), the inversion results of reservoir and fluid properties, as well as fracture parameters, are obtained. Here, reservoir and fluid properties are the basic parameters input to the model. By adjusting the reservoir and fracture parameters and fitting the double logarithmic curves of the measured data, the purpose of inverting reservoir and fracture parameters is achieved. This step is mainly to obtain the parameters of a single fracture segment.

[0123] In other words, based on the established multi-zone coupled well test seepage model of non-uniform fractures in shale gas wells, the model parameters such as reservoir, fluid properties and fracture parameters are input to obtain the model calculation results. These related parameters are then adjusted to fit the double logarithmic curve drawn from the measured data as closely as possible. When the fitting effect is ideal, the input fracture parameters are the fracture parameters obtained by the final inversion.

[0124] Figure 3 The two types of box graphs represent measured data (measured data Δp and Δp′), while the two lines are the results calculated from the multi-zone coupled well test seepage model of non-uniform fractures in shale gas (fitted data Δp and Δp′). This result is calculated from the input reservoir, fracture, and other model parameters; in this case, the input fracture parameters are the inversion results. Different input fracture parameters result in different calculated curves and different fitting effects. The fracture parameters with the better fitting effect are used as the fracture parameter inversion results. Figure 3 The fitted data is the curve of the model calculation result, which is the double logarithmic curve of the fitted pressure difference and the derivative of the pressure difference. Figure 3 The fitted curve is close to the double logarithmic curve drawn based on bottom hole pressure data. The fracture parameters at this time are used as the fracture parameter inversion result, and the fracture inversion parameters can be obtained.

[0125] S6. Determine if the crack parameter inversion results are too high. Crack parameters include the average crack half-length and the total crack length per segment. Specifically, compare the average crack half-length and the total crack length per segment of adjacent segments. Segments with high crack parameters are those where the total crack length per segment and the average crack half-length are higher than those of adjacent segments. For example, if the average crack half-length and the total crack length per segment of segment k are significantly greater than those of segments k-1 and k+1, then segment k is a segment with high crack parameters.

[0126] For example, by Figure 4AIt can be seen that the average crack half-length of segment k is significantly higher than that of segments k-1 and k+1; the average crack half-length of segment k+2 is significantly higher than that of segments k+1 and k+3; from Figure 4B It can be seen that the total seam length of segment k is significantly higher than that of segments k-1 and k+1; the total seam length of segment k+2 is significantly higher than that of segments k+1 and k+3. Therefore, segments k and k+2 are judged to be relatively high.

[0127] S7. Determine the relationship between the parent and child well groups and analyze the morphological characteristics of the differential pressure and differential pressure derivative curves in sections with high fracture parameters to determine whether pressure channeling has occurred. S7 specifically includes:

[0128] S701, Well Group Relationship I. Situation Judgment.

[0129] Well group relationship 1: The parent well is a fractured and operational well, and the daughter well is a fractured well. Comparing the high fracture parameter sections with the double logarithmic curves of pressure differential and pressure differential derivatives of the adjacent sections, if Δp... k >Δp k-1 Δp k >Δp k+1 In the linear flow phase, Δp′ k <Δp′ k-1 , Δp′ k <Δp′ k+1 Then, the k-th segment (the segment with high crack parameters) is a pressure channeling segment. For example, if... Figure 5 As shown in the diagram, in the case of a fractured well-production well relationship, the differential pressure curve of segment k is higher during the reservoir stage, and flatter during the linear flow stage. This is reflected in the wellbore reservoir stage by Δp. k >Δp k-1 Δp k >Δp k+1 In the linear flow phase, there exists Δp′ k <Δp′ k-1 , Δp′ k <Δp′ k+1 The situation. Figure 5 In the diagram, the three curves at the top represent pressure difference curves, and the three curves at the bottom represent pressure difference derivative curves.

[0130] Here, Δp k Δp represents the pressure difference in the k-th segment (the segment with the highest total crack length and the highest average crack half-length), in MPa; k-1 Δp represents the pressure difference in the (k-1)th segment, in MPa; k+1 The pressure difference for the (k+1)th segment is expressed in MPa; Δp′ k Let be the pressure difference derivative of the k-th segment in the higher section, in MPa; Δp′ k-1 Let Δp′ be the pressure differential derivative of the (k-1)th segment, in MPa; k+1Let be the pressure differential derivative of the (k+1)th segment, in MPa.

[0131] S702, well group relationship second situation judgment.

[0132] Well group relationship two is as follows: the parent well is a fractured but not yet put into production well, and the daughter well is a fractured well. Analyze the pressure differential and its derivative (double logarithmic curves) in the high-parameter fracture section, and the relationship between the bottom-hole pressure in the high-parameter fracture section and the bottom-hole pressure of the parent well. If the pressure differential derivative curve has a -1 / 2 slope in the transition phase, and the bottom-hole pressure in the high-parameter fracture section is less than the bottom-hole pressure of the parent well, then this k-th segment (high-parameter fracture section) is a pressure channeling segment. For example, if... Figure 6 As shown, in the case of a fractured well-fractured well relationship, the differential pressure derivative curve of the kth segment has a slope of -1 / 2 in the transition stage.

[0133] Exemplary Example 2

[0134] This exemplary embodiment provides a shale gas well inter-well pressure channeling identification system. This shale gas well inter-well pressure channeling identification system can implement the shale gas well inter-well pressure channeling identification method described in Exemplary Embodiment 1 above.

[0135] like Figure 7 As shown, the shale gas well inter-well pressure channeling identification system may include: a data collection unit, a bottom hole pressure calculation unit, a curve plotting unit, a well test seepage model unit, an inversion unit, a judgment unit, and a discrimination unit.

[0136] The data collection unit, bottom hole pressure calculation unit, and curve plotting unit are connected in sequence. The inversion unit is connected to the well test flow model unit and the curve plotting unit. The inversion unit, judgment unit, and discrimination unit are connected in sequence. The judgment unit is connected to the well test flow model unit.

[0137] The data collection unit is configured to conduct well test analysis during the pressure drop phase after pump shutdown following fracturing, collecting fracturing operation data, reservoir parameters, fluid properties, and well completion data; the bottom hole pressure calculation unit is configured to calculate the bottom hole pressure and eliminate pressure data oscillations caused by water hammer; the curve plotting unit is configured to plot double logarithmic curves of pressure differential and its derivative based on the bottom hole pressure data; the well test seepage model unit is configured to establish a multi-zone coupled well test seepage model for non-uniform fractures in shale gas wells; and the inversion unit is configured based on the established shale gas well... A non-uniform fracture multi-zone coupled well test seepage model is used. The input model parameters are adjusted, and the double logarithmic curves of pressure difference and pressure difference derivative are fitted. When the curve calculated by the model is close to the double logarithmic curves of pressure difference and pressure difference derivative of the curve plotting unit, the fracture parameters in the input model parameters are the fracture parameters obtained by inversion. The judgment unit is configured to judge whether the fracture parameters obtained by the inversion unit are too high. The discrimination unit is configured to determine the relationship between the parent and child well groups and analyze the morphological characteristics of the pressure difference and pressure difference derivative curves in the section with high fracture parameters to determine whether there is pressure channeling.

[0138] The shale gas well inter-well pressure crosstalk identification method according to the present invention can be programmed into a computer program and the corresponding program code or instructions can be stored in a computer-readable storage medium. When the program code or instructions are executed by a processor, the processor performs the above-described shale gas well inter-well pressure crosstalk identification method. The processor and memory can be included in a computer device.

[0139] An exemplary embodiment of another aspect of the present invention also provides a computer-readable storage medium storing a computer program. The computer-readable storage medium stores a computer program that, when executed by a processor, causes the processor to execute the shale gas well inter-well pressure crosstalk identification method according to the present invention. The computer-readable recording medium is any data storage device capable of storing data readable by a computer system. Examples of computer-readable recording media include: read-only memory, random access memory, read-only optical disk, magnetic tape, floppy disk, optical data storage device, and carrier waves (such as data transmission via the Internet through wired or wireless transmission paths).

[0140] An exemplary embodiment of another aspect of the present invention also provides a computer device. The computer device includes a processor and a memory. The memory stores a computer program. The computer program is executed by the processor, causing the processor to execute the computer program for the shale gas well inter-well pressure crosstalk identification method according to the present invention.

[0141] In summary, the beneficial effects include:

[0142] This invention provides a method, system, equipment, and medium for identifying inter-well pressure channeling in shale gas wells. The core element is the pressure channeling identification method. In S1, the pressure drop data during the pump shutdown stage of the actual fracturing operation pump pressure curve is directly used as the measured data for well test analysis, effectively avoiding the problem of long-term well shut-in pressure measurement required in traditional well test analysis. In S2, a filtering and noise reduction method is used to denoise the data, improving the quality of the well test data and the accuracy of well test interpretation. In S3, a multi-zone coupled well test seepage model of non-uniform fractures in shale gas wells is established. Compared with existing well test models, this model can characterize single-segment hydraulic fractures while balancing model calculation efficiency and solution accuracy. Compared with existing technologies, this invention can identify pressure channeling not only between fracturing wells and production wells but also between fracturing wells, effectively solving the problem of pressure channeling identification when dynamic production data is lacking.

[0143] Although a method, system, device and medium for identifying inter-well pressure channeling in shale gas wells according to the present invention have been described above in conjunction with exemplary embodiments, those skilled in the art should understand that various modifications and changes can be made to the exemplary embodiments of the present invention without departing from the spirit and scope defined by the claims.

Claims

1. A method for identifying inter-well pressure channeling in shale gas wells, characterized in that, The method includes: During the pressure drop phase after pump shutdown following fracturing, well test analysis was conducted to collect fracturing operation data, reservoir parameters, fluid properties, and well completion data. Calculate the bottom hole pressure and eliminate pressure data oscillations caused by water hammer effect; Based on bottom hole pressure data, plot double logarithmic curves of pressure difference and its derivative; Establish a multi-zone coupled well test seepage model for non-uniform fractures in shale gas wells; Based on the established multi-zone coupled well test seepage model of non-uniform fractures in shale gas wells, the input model parameters are adjusted, and the double logarithmic curves of pressure difference and pressure difference derivative are fitted. When the curve of the model calculation result is close to the double logarithmic curves of pressure difference and pressure difference derivative drawn based on the bottom hole pressure data, the fracture parameters in the input model parameters are the fracture parameters obtained by inversion. Determine if the crack parameters obtained from the inversion are too high; if they are too high, then... Determine the relationship between the parent and child well groups and analyze the morphological characteristics of the pressure difference and pressure difference derivative curves in the high-parameter fracture sections to determine whether pressure channeling is present.

2. The method for identifying inter-well pressure channeling in shale gas wells according to claim 1, characterized in that, The fracturing operation data, reservoir parameters, fluid properties parameters, and well completion data include: fracturing operation pump pressure data, pump injection rate, gas properties parameters, original formation pressure, formation temperature, comprehensive compressibility coefficient, permeability, porosity, fracturing fluid viscosity and density, well perforation location coordinates, number of clusters per segment, cluster spacing, fracturing segment depth, and wellbore trajectory coordinates.

3. The method for identifying inter-well pressure channeling in shale gas wells according to claim 1, characterized in that, The calculated bottom hole pressure includes: p B =p h +r f gZ w formula 1 Where, p B The bottom hole pressure is in MPa; p h ρ is the wellhead pump pressure, MPa; f The density of the fracturing fluid is kg / m³. 3 Z w ρ is the vertical depth of the fracturing section, in km; g is the acceleration due to gravity, in m / s². 2 .

4. The method for identifying inter-well pressure channeling in shale gas wells according to claim 1, characterized in that, The elimination of pressure data oscillations caused by water hammer effect includes: using Gaussian filtering to denoise the pressure data oscillations caused by water hammer effect after rapid pump shutdown.

5. The method for identifying inter-well pressure channeling in shale gas wells according to claim 1, characterized in that, Based on the bottom hole pressure after oscillation elimination, a double logarithmic curve of the pressure difference and its derivative is plotted. The formulas for calculating the pressure difference and its derivative are as follows: Where, Δp i p is the pressure difference at the i-th time step; i p1 is the pressure at the i-th time step, MPa; p1 is the initial pressure at the time step, MPa; Δp i ' is the derivative of the pressure difference at the i-th time step, MPa; Δp1 is the initial time pressure difference, MPa; Δt i The time difference between the i-th time step and the initial time; t i Let i be the time.

6. The method for identifying inter-well pressure channeling in shale gas wells according to claim 1, characterized in that, The non-uniform fracture multi-zone coupled well test seepage model for shale gas wells is as follows: in, The dimensionless pseudo-pressure is applied to the microcracks in the outer zone. The outer matrix is ​​dimensionless pseudo-pressure; The internal microcracks are dimensionless pseudo-pressures. ω1 represents the dimensionless pseudo-pressure of the inner zone matrix; s is a Laplace variable, dimensionless; ω1 is the outer zone reservoir ratio, dimensionless; ω2 is the inner zone reservoir ratio, dimensionless; q Di,j Let x be the dimensionless linear density flow rate of the j-th segment of the hydraulic fracture in the i-th inner zone of the pull-type space; Г1 is the outer zone boundary; Г2 is the inner zone boundary; x D y D η is a dimensionless unit of length; η is the ratio of the pressure conductivity coefficient of the outer region to that of the inner region; W i S represents the number of discrete hydraulic fractures in the inner zone; Di,j For the i-th inner zone, the j-th hydraulic fracture segment has a dimensionless length; δ() is the Dirac function; x i,j ,y i,j For the i-th inner zone, the location of the j-th hydraulic fracture; t D denoted as dimensionless time; n is the direction of the boundary normal vector; M is the ratio of permeability between the outer and inner zones; x and y are the positioning coordinates in the rectangular coordinate system; j refers to the j-th segment of the hydraulic fracture; the inner zone is the complex fracture network area generated by the fracturing operation; the outer zone is the area unaffected by the fracturing operation.

7. The method for identifying inter-well pressure channeling in shale gas wells according to claim 1, characterized in that, The determination of whether the crack parameters obtained by inversion are too high includes: determining whether the average crack half length and the total crack length of a single segment in the kth segment are higher than those of the adjacent segments. If so, the kth segment is a segment with high crack parameters.

8. The method for identifying inter-well pressure channeling in shale gas wells according to claim 7, characterized in that, The determination of the relationship between the parent and child well groups and the analysis of the pressure differential and pressure differential derivative curve morphology characteristics in the high fracture parameter sections include: If the parent well is a well that has been put into production after fracturing and the daughter well is a fracturing well, compare the double logarithmic curves of the pressure difference and pressure difference derivative of the section with high fracture parameters with the two adjacent sections. If the pressure difference of the section with high fracture parameters is greater than that of the two adjacent sections during the wellbore storage stage, and the pressure difference derivative of the section with high fracture parameters is less than that of the two adjacent sections during the linear flow stage, then the section with high fracture parameters is a pressure channeling section. If the parent well is a fractured but not yet put into production well, and the daughter well is a fractured well, if the differential pressure derivative curve of the section with high fracture parameters has a slope of -1 / 2 in the transition stage, and the bottom hole pressure is less than the bottom hole pressure of the parent well, then the section with high fracture parameters is the pressure channeling section.

9. A shale gas well inter-well pressure channeling identification system, characterized in that, The system includes a data collection unit, a bottom-hole pressure calculation unit, a curve plotting unit, a well test seepage model unit, an inversion unit, a judgment unit, and a discrimination unit; wherein... The data collection unit, bottom hole pressure calculation unit, and curve plotting unit are connected in sequence. The inversion unit is connected to the well test seepage model unit and the curve plotting unit. The inversion unit, judgment unit, and discrimination unit are connected in sequence. The judgment unit is connected to the well test seepage model unit. The data collection unit is configured to conduct well test analysis during the pressure drop phase after pump shutdown following fracturing, collecting fracturing operation data, reservoir parameters, fluid properties, and well completion data; The bottom hole pressure calculation unit is configured to calculate the bottom hole pressure and eliminate pressure data oscillations caused by water hammer effects. The curve plotting unit is configured to plot double logarithmic curves of pressure difference and pressure difference derivative based on bottom hole pressure data; The well test seepage model unit is configured to establish a multi-zone coupled well test seepage model for non-uniform fractures in shale gas wells; The inversion unit is configured to be based on the established multi-zone coupled well test seepage model of non-uniform fractures in shale gas wells. The input model parameters are adjusted, and the double logarithmic curves of pressure difference and pressure difference derivative are fitted. When the curve of the model calculation result is close to the double logarithmic curves of pressure difference and pressure difference derivative of the curve plotting unit, the fracture parameters in the input model parameters are the fracture parameters obtained by inversion. The judgment unit is configured to determine whether the crack parameters obtained by the inversion unit are too high; The discrimination unit is configured to determine the relationship between the parent and child well groups and analyze the morphological characteristics of the differential pressure and differential pressure derivative curves in the high-parameter fracture sections to determine whether there is pressure channeling.

10. A computer device, characterized in that, The device includes: processor; and The memory stores a computer program that, when executed by a processor, implements the shale gas well inter-well pressure crosstalk identification method as described in any one of claims 1 to 8.

11. A computer-readable storage medium storing a computer program, characterized in that, When the computer program is executed by the processor, it implements the shale gas well inter-well pressure crosstalk identification method as described in any one of claims 1 to 8.

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