An evaluation method for unconventional reservoir volumetric fracturing based on material balance

Abstract

A material balance-based method for evaluating the effectiveness of volumetric fracturing in unconventional reservoirs is proposed. First, a set of material balance equations for volumetric fracturing in unconventional reservoirs is established. Then, by designing a calculation process and developing a multi-well synchronous solution program, key evaluation parameters for the volumetric fracturing effect of each well are obtained. Finally, the proportion of injected fluid in each volume during the volumetric fracturing process is quantitatively analyzed, resulting in theoretical charts of volumetric fracturing effect evaluation parameters under different construction parameters. Taking a typical well group in an actual unconventional reservoir block as an example, the volumetric fracturing effect at different well network development stages is quantitatively evaluated. This method, based on material balance, offers a simple parameter input and calculation process, and can provide timely guidance for well network adjustments and comprehensive management of unconventional oil and gas reservoirs.

Description

Technical Field

[0001] This invention relates to the field of unconventional reservoir volumetric fracturing technology, and in particular to a method for evaluating the effect of unconventional reservoir volumetric fracturing based on material balance. Background Technology

[0002] The fundamental purpose of fracturing effect evaluation is to improve the success rate of fracturing operations, optimize fracturing design and technology, achieve post-fracturing production enhancement, and guide post-fracturing production work. The evaluation of volumetric fracturing effect is actually a comprehensive judgment of the overall quality of fracturing operations. In a narrow sense, it mainly evaluates parameters related to changes in reservoir stimulation volume, fracture conductivity, and fracture density (geometric parameters) after fracturing in a single well. In a broader sense, it is a comprehensive evaluation of dynamic monitoring of fracturing operations in a single well or block, the compliance rate between the process and design during construction, long-term production capacity, and economic efficiency.

[0003] In recent years, major oil and gas fields at home and abroad have successively carried out a large number of research studies on the evaluation of fracturing effects. Based on the timeliness and object-specificity of the evaluation results, these evaluation methods can be divided into direct methods and indirect methods.

[0004] The direct method involves acquiring data through instrument monitoring, interpreting various parameters related to the fracture, and then evaluating the fracturing effect. Examples include microseismic fracture monitoring, isotope tracers, and inclinometers.

[0005] Indirect methods involve inverting fracture geometry parameters and fracture conductivity after fracturing using production test data, including fracturing well production dynamics analysis, well test evaluation, and mathematical model analysis. For example, in "Petroleum Exploration and Development," 2020, 47(2): 409-415, Zhang Anshun, Yang Zhengming, Li Xiaoshan, et al., "A Method for Evaluating the Effect of Volumetric Fracturing Stimulation in Vertical Wells of Low-Permeability Reservoirs" [J]. This belongs to the indirect method. Another example is in "Journal of China University of Petroleum (Natural Science Edition)," 2019, 43(1): 81-89, Feng Fuping, Huang Rui, Lei Yang, et al., "An Evaluation Model and Application of Volumetric Fracturing Engineering Stimulation Effect Based on Energy Theory" [J]. This belongs to the indirect method. Yet another example is in "Science, Technology and Engineering," 2015, 15(36): 56-62, Li Xianwen, Zhang Kuangsheng, Ma Bing, et al., "A New Method for Explaining the Effective Stimulation Volume of Volumetric Fracturing in Tight Reservoirs Based on the Principle of Material Balance," which belongs to the indirect method.

[0006] However, both the direct and indirect methods have their problems. The fracture network stimulation volume obtained by the direct method is much larger than the effective stimulation volume; while the indirect method has multiple solutions and does not consider the fracturing and seepage effects, which limits the accurate evaluation of the volumetric fracturing effect of horizontal wells in unconventional reservoirs. Summary of the Invention

[0007] To overcome the shortcomings of existing technologies and accurately reflect the degree of fracturing in unconventional reservoirs, this invention aims to provide a method for evaluating the effectiveness of volumetric fracturing in unconventional reservoirs based on material balance. Utilizing known fracturing construction and production dynamics data, and based on the principle of material balance, this method comprehensively considers microscopic mechanisms such as the degree of natural fracture development, the influence of stress difference on fracture network morphology, and the permeation of fracturing fluid. This provides a new method for rapidly and accurately evaluating the effectiveness of volumetric fracturing in unconventional oil reservoirs. It features simple parameter input and calculation steps and can promptly guide the adjustment of development well networks and comprehensive management of unconventional oil and gas reservoirs.

[0008] To achieve the above object, the technical solution of the present invention is:

[0009] A method for evaluating the effectiveness of unconventional reservoir volumetric fracturing based on material balance includes the following steps:

[0010] Step 1: Establish the material balance equations for unconventional reservoir volumetric fracturing.

[0011] Based on the principle of mass conservation in the fracturing injection fluid system, a material balance equation for unconventional reservoir volume fracturing is established. The total amount of fracturing fluid injected includes: wellbore volume, main fracture pore volume, secondary fracture network pore volume, and matrix pore volume near the entire fracture network. A calculation model for the above four volumes is established. Material balance equations for the seepage process, elastically driven material balance equations and state equations are also established.

[0012] Step 2: Solving and Verifying the Material Balance Equation for Volumetric Fracturing

[0013] Based on the actual geological, fluid, and rock mechanics parameters of the target reservoir in the study area, and combined with oil well fracturing data, the established set of unconventional reservoir volume fracturing material balance equations is solved simultaneously. This allows us to obtain the effective support length of the fracturing fractures, the equivalent penetration depth, the average formation pressure after penetration, and the average formation pressure after fracturing flowback for each oil well. Furthermore, the reliability of the above material balance equations is verified based on the actual development of typical well groups.

[0014] Step 3: Quantitative Evaluation of the Effect of Volumetric Fracturing in Unconventional Reservoirs

[0015] The effective supported fracture length and equivalent permeation depth were obtained by solving the unconventional reservoir volumetric fracturing material balance equation. The wellbore volume, main fracture volume, secondary fracture network volume, and secondary fracture network permeation volume were calculated respectively to obtain the proportion of injected fluid volume in each of the wellbore, main fracture, secondary fracture network, and matrix permeation volumes during the volumetric fracturing process. Sensitivity analysis of the volumetric fracturing effect was conducted to obtain the influence of different total injection volumes of fracturing fluid and different numbers of fracturing stages on the volumetric fracturing fracture network parameters. Based on the volumetric fracturing construction of typical well groups in the target reservoir of the study area at different well network development stages, the volumetric fracturing effect of the target reservoir at different well network development stages was quantitatively evaluated.

[0016] The specific steps of step one are as follows:

[0017] (1) Establish a physical model for the propagation of the volumetric fracturing fracture network in unconventional reservoirs and its assumptions;

[0018] (2) Establish a wellbore volume calculation model. The wellbore volume is calculated from the wellbore radius and drilling footage according to the cylinder volume formula.

[0019] (3) Establish a calculation model for the pore volume of the main fracture; the pore volume of the main fracture is calculated from the half-length, height and width data of the main fracture according to the formula of cuboid volume, wherein: the half-length of the main fracture is an unknown parameter to be solved; the height of the main fracture is equal to the thickness of the target reservoir in the study area; the distribution of the width of the main fracture satisfies the England & Green equation under plane strain conditions.

[0020] (4) Establish a pore volume calculation model for the secondary fracture network. The secondary fracture network is formed by the crisscrossing expansion of multiple sets of natural fractures activated during the expansion of the main fracture. Its expansion distance depends on the number, spacing, and stress distribution of natural fractures in the target reservoir in the study area, and can be determined comprehensively based on the rock mechanical characteristic parameters of the target reservoir and imaging logging data. The width of the activated natural fractures (secondary fractures) can be determined based on the core data of the specific block, and the height is equal to the thickness of the target reservoir. Since the pore area of ​​the secondary fracture network on the plane can be summed and equivalently represented as an ellipse with the same length as the main fracture, the pore volume of the secondary fracture network can be calculated according to the cylinder volume formula from the major axis, minor axis, and cylinder height data of the planar elliptical physical model.

[0021] (5) Establish a calculation model for the volume of matrix pores near the entire fracture network, and introduce the depth of permeation to characterize and evaluate the effect of permeation replacement on the matrix pores near the entire fracture network. The volume of matrix pores near the fracture network is the difference between the volume of the cylinder and the volume of the main fracture pores, the volume of the secondary fracture network pores, and the volume of no permeation, forming the material balance equation of the fracturing injection fluid system; and establish the material balance equation of the permeation process based on the difference in saturation before and after permeation and the permeation recovery data obtained from the laboratory experiment.

[0022] (6) Establish the relationship between the injection volume of fracturing fluid and the changes in formation pressure and underground pore volume after the fracturing fluid has undergone the seepage effect, and the relationship between the surface production of oil wells and the changes in formation pressure and underground pore volume during the fracturing flowback period. These are used as the material balance equations for the reservoir elastic drive during the fracturing flowback period. State equations related to pore volume changes before fracturing, after seepage and after flowback are given. Finally, an unconventional reservoir volume fracturing material balance equation set is formed, which is an unconventional reservoir volume fracturing effect evaluation model based on material balance.

[0023] The aforementioned model for calculating the pore volume of the secondary fracture network is as follows:

[0024] The secondary fracture network is formed by the crisscrossing expansion of multiple sets of natural fractures activated during the propagation of the main fracture. The propagation distance depends on the density, spacing, and stress distribution of natural fractures in the target reservoir of the study area, and is determined comprehensively based on the rock mechanical characteristics parameters of the target reservoir and imaging logging data. The width of the activated natural fractures (secondary fractures) is determined based on core data from specific blocks, while the height is equal to the thickness of the target reservoir. Since the summation of the pore areas of the secondary fracture network on the plane is equivalent to an ellipse with the same major axis as the length of the main fracture, the pore volume of the secondary fracture network is calculated according to the cylinder volume formula, using the major axis, minor axis, and cylinder height data of the planar elliptical physical model. Among them, the relationship between the major axis 2a and the minor axis 2b is related to the geostress difference and is determined based on the ratio r of the longitudinal and transverse lengths of the fractures in the single-segment fracturing network in the microseismic monitoring data of the study area, i.e., a = x. f =rb; If the secondary fracture height is equal to the target reservoir thickness H, then the secondary fracture network pore volume calculation model is expressed as:

[0025]

[0026] In the formula: V s The pore volume represents the secondary fracture network.

[0027] The matrix pore permeation volume calculation model is as follows:

[0028] According to the theory of rapid surface infiltration, spontaneous infiltration is considered to begin from the surface of the core and proceed layer by layer into the core interior. The early infiltration stage occurs at the core surface. Based on the dual-medium assumption, the entire elliptical cylinder is considered to be divided into many matrix blocks by a crisscrossing fracture network. Each matrix block is equivalent to an experimental core, and the fracture network is filled with water. For each matrix block, it is equivalent to the matrix block being immersed in fracturing fluid within the network of fractures. The rapid surface infiltration of all matrix blocks is equivalent to the surface infiltration of the entire elliptical cylinder. Introducing infiltration depth to characterize and evaluate the effect of infiltration displacement on the matrix pores near the entire fracture network, the calculation model for the infiltration volume of the matrix pores near the entire fracture network is expressed as follows:

[0029]

[0030] In the formula: V f φ1 represents the matrix pore volume of infiltration; d represents the equivalent infiltration depth; and φ1 represents the matrix porosity after infiltration displacement.

[0031] The mass balance equation for the adsorption process is as follows:

[0032] The amount of oil recovered through percolation is equal to the decrease in oil saturation in the matrix pore volume. Based on the difference in saturation before and after percolation and the degree of percolation recovery obtained from laboratory core percolation experiments, a material balance equation for the percolation process is established:

[0033]

[0034] In the formula: S oi 、S or These represent the initial oil saturation of the core before infiltration begins and the residual oil saturation of the core after infiltration ends; R o This represents the core seepage recovery rate.

[0035] The specific steps of step two are as follows:

[0036] (1) Basic data preparation; Based on the existing geological development characteristics research results of the target reservoir in the study area, the reservoir geological characteristic parameters, formation rock mechanical parameters, fracturing construction parameters of each well and production dynamic data statistics during the flowback period were compiled.

[0037] (2) Solving the evaluation model of unconventional reservoir volumetric fracturing effect based on material balance. Based on the unconventional reservoir volumetric fracturing material balance equation set and the closed equation characteristics of the four unknowns established in step one, the calculation process is designed and a multi-well synchronous solution program is compiled. Finally, the key evaluation parameters of each oil well are obtained, including: effective support length of fracturing fracture, equivalent permeation depth, average formation pressure after permeation and average formation pressure after fracturing flowback. Furthermore, the volumes of each part can be calculated, including wellbore volume, main fracture volume, secondary fracture network volume, and matrix permeation volume.

[0038] (3) Verification of the reliability of the solution results of the material balance equation for unconventional reservoir volumetric fracturing. Based on the microseismic monitoring data of the fractured wells in the field, the actual well spacing and development dynamics, the reliability of the solution results of the above material balance equations was comprehensively verified.

[0039] The specific steps of step three are as follows:

[0040] (1) The effective support fracture length and equivalent permeation depth obtained by solving the unconventional reservoir volumetric fracturing material balance equation set were used to calculate the wellbore volume, main fracture volume, secondary fracture network volume and secondary fracture network permeation volume, respectively. The proportion of the injected fluid volume in each part of the volume (wellbore, main fracture, secondary fracture network and matrix permeation) during the volumetric fracturing process was obtained, revealing the key role of fracturing fluid permeation and replacement in the development of unconventional reservoirs.

[0041] (2) Sensitivity analysis of volumetric fracturing effect in unconventional reservoirs. A single-factor analysis method was used to evaluate the influence of different total fracturing fluid injection volumes and different number of fracturing stages in horizontal wells on the effective fracture network length, single-stage fracture network stimulation volume, single-stage fracture network permeation volume and equivalent permeation depth, providing a convenient chart for quantitative evaluation of the volumetric fracturing effect in actual blocks;

[0042] (3) Quantitative evaluation of the volumetric fracturing effect in unconventional reservoirs. Based on the volumetric fracturing construction of typical well groups in the target reservoir of the study area at different well network development stages, the length and width of the fracture network in the volumetric fracturing section of each horizontal well are quantitatively calculated. Based on the planar distribution of the well network and fracture network, the overlap relationship between the volumetric fracturing fracture networks of each well is determined, and the volumetric fracturing effect of the target reservoir in the study area at different well network development stages is quantitatively evaluated.

[0043] The beneficial effects of this invention are as follows: The unconventional reservoir volumetric fracturing effect evaluation method based on material balance described in this invention considers the permeation and displacement mechanism between the fracturing network and matrix pores, as well as the material balance principle of the injected and produced fluid systems during fracturing and flowback processes, thus overcoming the shortcomings of previous models that did not take all factors into account. Furthermore, it quantitatively describes and evaluates the overlap relationship between the volumetric fracturing network by using the planar distribution positions of the well network and fracture network, forming an unconventional reservoir volumetric fracturing effect evaluation method based on material balance. This method reveals the key role of fracturing fluid permeation and displacement in the development of unconventional reservoirs, reasonably explains the generally low flowback rates in unconventional reservoirs, provides engineers with convenient reference charts for quantitative evaluation of the volumetric fracturing effect in actual blocks, and can promptly guide oil and gas fields to make reasonable well placement and development measures adjustments. It has significant practical implications for the rational development of unconventional reservoirs and has certain application value. Compared with existing methods, it has the following advantages:

[0044] 1. An evaluation model for the effect of unconventional reservoir volumetric fracturing based on material balance;

[0045] 2. Simultaneous multi-well solution of key evaluation parameters for volumetric fracturing effect in unconventional reservoirs;

[0046] 3. Quantitative evaluation of the overlap relationship of volumetric pressure fracture network in unconventional reservoirs. Attached Figure Description

[0047] Figure 1 This is a schematic diagram (top view) of the physical model of the volumetric fracturing fracture network.

[0048] Figure 2 This is a schematic diagram of the seepage depth in the fracture network.

[0049] Figure 3 This is a flowchart for evaluating the effectiveness of unconventional reservoir volumetric fracturing based on material balance.

[0050] Figure 4 It is the proportion of the injected fracturing fluid in the volume of each part.

[0051] Figure 5 This describes the influence of different total injection volumes of fracturing fluid and different numbers of fracturing stages on the effective support fracture length.

[0052] Figure 6 This study investigates the influence of different total fracturing fluid injection volumes and different numbers of fracturing stages on the volume of a single-stage fracture network.

[0053] Figure 7 This study investigates the influence of different total injection volumes of fracturing fluid and different numbers of fracturing stages on the permeation volume of a single fracture network.

[0054] Figure 8This describes the influence of different total injection volumes of fracturing fluid and different numbers of fracturing stages on the equivalent penetration depth.

[0055] Figure 9 This is a schematic diagram of the overlap relationship between the basic well network and fracture network of a typical well group in the target reservoir of the study area for volumetric fracturing.

[0056] Figure 10 This is a schematic diagram of the overlapping relationship of the well network and fracture network in a typical well group of the target reservoir in the study area during volumetric fracturing.

[0057] Figure 11 This is a schematic diagram of the overlapping relationship of the secondary intensification well network and fracture network in a typical well group of the target reservoir in the study area. Detailed Implementation

[0058] The embodiments of the present invention will be described in detail below with reference to the accompanying drawings.

[0059] A method for evaluating the effectiveness of unconventional reservoir volumetric fracturing based on material balance includes the following steps:

[0060] Step 1: Establish the mass balance equations for unconventional reservoir volumetric fracturing. Based on the principle of mass conservation in the fracturing injection fluid system, establish the mass balance equations for unconventional reservoir volumetric fracturing. The total volume of fracturing fluid injected includes: wellbore volume, primary fracture pore volume, secondary fracture network pore volume, and matrix pore volume near the entire fracture network. Establish calculation models for these four volumes. Furthermore, establish the mass balance equations for the adsorption process, the elastically driven mass balance equations during the fracturing flowback period, and the equations of state.

[0061] The specific steps of step one are as follows:

[0062] (1) Establish a physical model for the propagation of the volumetric fracturing fracture network in unconventional reservoirs and its assumptions;

[0063] Reference Figure 1 Based on the fluid seepage equation and continuity equation of porous media, and considering the interaction between fluid and fractures and between fractures, it is assumed that a single-segment volumetric fracturing network is composed of a series of orthogonal primary and secondary fractures in a regular combination, forming an axisymmetric elliptical cylinder shape along the wellbore, with the major and minor axes of the ellipse being 2a and 2b, respectively. A physical model for the expansion of unconventional reservoir volumetric fracturing network is established—the elliptical orthogonal network model.

[0064] Assumptions: ① It is assumed that the primary and secondary fractures traverse the entire reservoir thickness and are parallel to the directions of the maximum and minimum horizontal principal stresses; ② The spatial variation of fracture extension is considered, i.e., it conforms to the elliptical orthogonal network model; ③ It is assumed that the secondary fractures are at each horizontal principal stress (the maximum and minimum horizontal principal stresses are σ...). H σ h) The proppant is uniformly distributed in the direction (with spacings of dx and dy) and the fracture width is the same; ④ The effects of viscoelasticity and wall slip on fluid flow are ignored; ⑤ It is assumed that the proppant is uniformly distributed in the fracture; ⑥ Since the permeability of the unconventional reservoir matrix is ​​extremely low, the mass of fluid lost into the matrix is ​​relatively small compared to the overall mass of the fracturing fluid injected in large volumes, so the effect of fracturing fluid loss is ignored.

[0065] (2) Establish a wellbore volume calculation model. The wellbore volume is calculated using the formula for the volume of a cylinder, based on the wellbore radius and drilling footage:

[0066] The wellbore volume calculation model can be represented as:

[0067]

[0068] In the formula: V w r is the wellbore volume; w L is the wellbore radius; L is the drilling footage.

[0069] (3) Establish a calculation model for the pore volume of the main fracture; the pore volume of the main fracture is calculated from the half-length, height and width data of the main fracture according to the formula for the volume of a cuboid. Among them: the half-length of the main fracture is an unknown parameter to be solved; the height of the main fracture is equal to the thickness of the target reservoir in the study area; the distribution of the width of the main fracture satisfies the England & Green equation under plane strain conditions (Reference: ENGLAND AH, GREEN A E. Some two-dimensional punch and crack problems in classical elasticity[J]. Mathematical Proceedings of the Cambridge Philosophical Society, 1963, 59(2):489-500);

[0070] ① The distribution of the main crack width satisfies the England & Green equation under plane strain conditions:

[0071]

[0072] In the formula: w f Main fracture width; υ is reservoir Poisson's ratio; E is reservoir elastic modulus; h f The main crack is high; p f The net pressure within the crack is σ; for ease of calculation, the arithmetic mean of the maximum and minimum horizontal principal stresses is used. min This represents the minimum horizontal principal stress of the reservoir.

[0073] ②The calculation model for the pore volume of the main fracture can be expressed as:

[0074] V f =2x f w f H (3)

[0075] In the formula: V f Main fracture pore volume; x f The main fracture half-length (half the effective support length of the fracturing fracture), which is half the major axis of the elliptical physical model; H is the target reservoir thickness in the study area.

[0076] (4) Establish a calculation model for the pore volume of the secondary fracture network. The secondary fracture network is formed by the crisscrossing expansion of multiple sets of natural fractures activated during the expansion of the main fracture. Its expansion distance depends on the density, spacing, and stress distribution of natural fractures in the target reservoir of the study area, and can be determined comprehensively based on the rock mechanical characteristic parameters of the target reservoir and imaging logging data. The width of the activated natural fractures (secondary fractures) can be determined based on the core data of the specific block, and the height is equal to the thickness of the target reservoir. Since the pore area of ​​the secondary fracture network on the plane can be summed and equivalently represented as an ellipse with the same major axis as the length of the main fracture, the pore volume of the secondary fracture network can be calculated according to the cylinder volume formula from the major axis, minor axis, and cylinder height data of the planar elliptical physical model.

[0077] ①Natural fracture density, spacing, and stress distribution. Based on the results of in-situ stress and rock mechanics laboratory tests, parameters such as the maximum / minimum horizontal principal stress, Poisson's ratio, elastic modulus, tensile strength, and compressive strength of the target reservoir in the study area are obtained. Based on imaging logging data of typical blocks, the number of natural fractures N within the length M of the target reservoir segment in the study area is counted, and the natural fracture density N / M and spacing M / N can be calculated.

[0078] ② Width of activated natural fractures (secondary fractures). Based on typical well core data, the difference in fracture width along different horizontal principal stress directions is observed to obtain the proportional relationship λ between the width of the primary fracture and the width of the secondary fracture, thereby determining the width w of the activated natural fractures (secondary fractures). s =λw f .

[0079] ③ Secondary fracture network pore volume. Since the summation of the pore areas of the secondary fracture network on a plane can be equivalent to an ellipse with a major axis equal to the length of the main fracture, the pore volume of the secondary fracture network can be calculated using the formula for the volume of a cylinder, based on the major axis 2a, minor axis 2b, and the height data of the elliptical physical model. Specifically, the relationship between the major axis 2a and the minor axis 2b is related to the geostress difference and can be determined based on the ratio r of the longitudinal and transverse lengths of the single-segment fracturing network fractures in the microseismic monitoring data of the study area, i.e., a = x. f=rb; The secondary fracture height is equal to the target reservoir thickness H. Therefore, the calculation model for the pore volume of the secondary fracture network can be expressed as:

[0080]

[0081] In the formula: V s The pore volume represents the secondary fracture network.

[0082] (5) Establish a calculation model for the adsorption volume of matrix pores near the entire fracture network. The adsorption depth is introduced to characterize and evaluate the effect of adsorption replacement on the matrix pores near the entire fracture network. The adsorption volume of matrix pores near the fracture network is the difference between the volume of the cylinder and the volume of the main fracture pores, the volume of the secondary fracture network pores, and the volume without adsorption, forming the material balance equation of the fracturing injection fluid system. Based on the saturation difference and adsorption recovery data obtained from laboratory experiments, the material balance equation of the adsorption process is established.

[0083] ① Calculation model for matrix pore adsorption volume. (Refer to...) Figure 2 According to the theory of rapid surface infiltration, spontaneous infiltration is considered to begin from the surface of the core and proceed layer by layer into the core interior, with the initial main infiltration stage occurring at the core surface. Based on the dual-medium assumption, in this model, the entire elliptical cylinder can be considered as being divided into many matrix blocks by a crisscrossing fracture network, each matrix block equivalent to an experimental core, with the fracture network filled with water. For each matrix block, it is equivalent to the matrix block being immersed in fracturing fluid within the network of fractures; therefore, the rapid surface infiltration of all matrix blocks can be equated to the surface infiltration of the entire elliptical cylinder. Introducing infiltration depth to characterize and evaluate the effect of infiltration displacement on the matrix pores near the entire fracture network, the calculation model for the infiltration volume of the matrix pores near the entire fracture network can be expressed as:

[0084]

[0085] In the formula: V f φ1 represents the matrix pore volume of infiltration; d represents the equivalent infiltration depth; and φ1 represents the matrix porosity after infiltration displacement.

[0086] ②Material balance equation of the fracturing injection fluid system. After the fracturing fluid is injected into the target well from the wellhead, its volume consists of four parts: wellbore volume, primary fracture pore volume, secondary fracture network pore volume, and matrix pore volume near the entire fracture network, i.e.:

[0087] Q = V w +m(V f +V s +V m (6)

[0088] In the formula: Q is the total amount of fracturing fluid injected into the target well; m is the number of fracturing stages in the well.

[0089] ③ Material balance equation during the infiltration process. The material balance during the infiltration process can be described as follows: the amount of oil produced by infiltration is equal to the decrease in oil saturation in the matrix pore volume. Based on the data of saturation difference and infiltration recovery degree before and after infiltration obtained from laboratory core infiltration experiments, the material balance equation during the infiltration process is established as follows:

[0090]

[0091] In the formula: S oi 、S or These represent the initial oil saturation of the core before infiltration begins and the residual oil saturation of the core after infiltration ends; R o This represents the core seepage recovery rate.

[0092] (6) Establish the relationship between the injection volume of fracturing fluid and the changes in formation pressure and underground pore volume after the fracturing fluid has undergone the seepage effect, and the relationship between the surface production of oil wells and the changes in formation pressure and underground pore volume during the fracturing flowback period. These are used as the material balance equations for the reservoir elastic drive during the fracturing flowback period. State equations related to pore volume changes before fracturing, after seepage and after flowback are given. Finally, an unconventional reservoir volume fracturing material balance equation set is formed, which is an unconventional reservoir volume fracturing effect evaluation model based on material balance.

[0093] ① Material balance equation for reservoir elastic drive during fracturing flowback. After fracturing fluid is injected into the formation, a network of fractures is formed, causing changes in the matrix porosity of the stirred zone. At this time, the reservoir is still a closed, unsaturated reservoir, and the driving mechanism remains elastic. When the reservoir produces a certain amount of fluid, the reservoir pressure decreases from the formation pressure after fracturing fluid injection to the current formation pressure, resulting in a decrease in reservoir pore volume and an expansion of the volume of bound water and crude oil in the reservoir. Using the principle of material balance, the relationship between the amount of fracturing fluid injected and the changes in formation pressure and underground pore volume after the fracturing fluid has undergone percolation is established:

[0094] Q i -V w -m(V f +V s ) = V c1 (1-s wc (c) o +c c (p1-p) i (8)

[0095] In the formula: Q i c is the fracturing fluid injection volume for a single section of a horizontal well; o c is the crude oil compressibility coefficient. cp is the compressibility coefficient of the reservoir volume; p1 is the mean formation pressure after the end of the seepage process; p i V represents the mean pressure of the original formation. c1 V is the reservoir pressure swept volume after the infiltration process ends, expressed as V c1 =4x f (L+S)Hφ1, where: S is the horizontal well spacing; φ1 is the porosity of the formation rock after the infiltration process ends.

[0096] Similarly, establish the relationship between the surface fluid production of the oil well after fracturing and flowback and the changes in formation pressure and underground pore volume:

[0097] N p B o +W p B w +V w +m(V f +V s ) = V c2 (c o +c c (p1-p2-p) l (9)

[0098] Where: N p Cumulative oil production during the return period; W p B represents the cumulative water production during the return flow period. o B is the crude oil volume coefficient; w p1 is the formation water volume factor; p2 is the average formation pressure after fracturing and flowback; p l The pressure loss of the fluid in the wellbore is expressed as p. l =0.0028h, where: h is the wellbore depth; V c2 V is the reservoir pressure swept volume after fracturing and flowback, expressed as V c2 =4x f (L+S)Hφ2, where: φ2 is the porosity of the formation rock after the hydraulic fracturing and flowback are completed.

[0099] ② Equation of State. The pore size of the rock skeleton after the infiltration process has ended satisfies the equation of state:

[0100] φ1=φ0[1+c p (p1-p i (11)

[0101] In the formula: c p is the compressibility coefficient of the matrix porosity.

[0102] The rock skeleton pores after hydraulic fracturing and flowback satisfy the equation of state:

[0103] φ2=φ0[1+cp (p1-p2-p l (12)

[0104] The above equations ultimately form a set of material balance equations for unconventional reservoir volumetric fracturing, namely, an evaluation model for the effect of unconventional reservoir volumetric fracturing based on material balance. The four key parameters to be solved are: effective support length of the fracturing fracture x f Equivalent infiltration depth d, average formation pressure p1 after infiltration, and average formation pressure p2 after backflow.

[0105] Step 2: Solving and Verifying the Material Balance Equations for Volumetric Fracturing. Based on the actual geological, fluid, and rock mechanics parameters of the target reservoir in the study area, and combined with oil well fracturing data, the established set of material balance equations for unconventional reservoir volumetric fracturing is solved simultaneously. This yields the effective fracture support length, equivalent percolation depth, average formation pressure after percolation, and average formation pressure after fracturing flowback for each oil well. The reliability of these material balance equations is then verified based on the actual development of typical well groups.

[0106] The specific steps of step two are as follows:

[0107] (1) Basic data preparation. Based on the existing geological development characteristics research results of the target reservoir in the study area, reservoir geological characteristic parameters, formation rock mechanical parameters, fracturing construction parameters of each well, and production dynamic data statistics during the flowback period were compiled.

[0108] Taking the unconventional tight reservoir in the Mazhong area of ​​the Santanghu Basin in my country as an example, based on the existing geological development characteristics of the target reservoir in the study area and the horizontal well fracturing and stimulation construction parameters, the main parameters of the study area are determined as follows:

[0109] Table 1. Statistical Table of Reservoir Geological Characteristic Parameters

[0110]

[0111] Table 2 Statistical Table of Formation Rock Mechanical Parameters

[0112]

[0113] Table 3. Statistical table of fracturing operation parameters and flowback period production dynamics for each well.

[0114]

[0115]

[0116]

[0117]

[0118] (2) Solving the evaluation model of unconventional reservoir volumetric fracturing effect based on material balance. Based on the material balance equation set of unconventional reservoir volumetric fracturing and the closed equation characteristics of the four unknowns established in step one, the calculation process is designed and a multi-well synchronous solution program is compiled. Finally, the key evaluation parameters of each oil well are obtained, including: effective support length of fracturing fracture, equivalent permeation depth, average formation pressure after permeation and average formation pressure after fracturing flowback. Furthermore, the volumes of each part can be calculated, including wellbore volume, main fracture volume, secondary fracture network volume, and matrix permeation volume.

[0119] ① Design the calculation process. Refer to... Figure 3 Based on the unconventional reservoir volumetric fracturing material balance equation set established in Step 1 and the closed equation characteristics of the four unknowns, a solution process for the material balance equation set is designed, including: a basic data preparation module, a parameter symbol explanation module, an equation set and programming solution module, and a volumetric fracturing effect evaluation parameter output module.

[0120] ② A multi-well synchronous solution program was developed. The program development environment is based on Windows 10, and the relevant code was written and designed using the Jupyter Notebook module of Anaconda3 (64-bit). Through the calculation of the fracture network model of multiple wells in the study area, the final simulation results are output in the form of an Excel spreadsheet. This program can perform calculations and solutions for multiple wells simultaneously.

[0121] ③ The key evaluation parameters for each oil well are finally obtained. The key evaluation parameters include: effective support length of the fracturing fracture, equivalent penetration depth, average formation pressure after penetration, and average formation pressure after fracturing flowback. The volumes of each part can be calculated, including wellbore volume, main fracture volume, secondary fracture network volume, and matrix penetration volume, as shown in Table 4.

[0122] Table 4. Statistical table of fracturing operation parameters and flowback period production dynamics data for each well.

[0123]

[0124]

[0125]

[0126]

[0127]

[0128]

[0129] (3) Verification of the reliability of the solution results of the material balance equation for unconventional reservoir volumetric fracturing. Based on the microseismic monitoring data of the fractured wells in the field, the actual well spacing and development dynamics, the reliability of the solution results of the above material balance equations was comprehensively verified.

[0130] Step 3: Quantitative Evaluation of the Effect of Volumetric Fracturing in Unconventional Reservoirs. Using the effective supported fracture length and equivalent permeation depth obtained from the unconventional reservoir volumetric fracturing material balance equation, the wellbore volume, main fracture volume, secondary fracture network volume, and secondary fracture network permeation volume are calculated respectively. This yields the proportion of injected fluid volume in each part of the volume (wellbore, main fracture, secondary fracture network, and matrix permeation) during the volumetric fracturing process. Sensitivity analysis of the volumetric fracturing effect is then performed to obtain the influence of different total injection volumes of fracturing fluid and different numbers of fracturing stages on the volumetric fracturing fracture network parameters. Based on the volumetric fracturing operations of typical well groups in the target reservoir of the study area at different well network development stages, the volumetric fracturing effect of the target reservoir in the study area at different well network development stages is quantitatively evaluated.

[0131] The specific steps of step three are as follows:

[0132] (1) The effective support fracture length and equivalent permeation depth obtained by solving the unconventional reservoir volumetric fracturing material balance equation set were used to calculate the wellbore volume, main fracture volume, secondary fracture network volume and secondary fracture network permeation volume, respectively. The proportion of the injected fluid volume in each part of the volume (wellbore, main fracture, secondary fracture network and matrix permeation) during the volumetric fracturing process was obtained, revealing the key role of fracturing fluid permeation and replacement in the development of unconventional reservoirs.

[0133] Reference Figure 4 Based on the wellbore volume, main fracture volume, secondary fracture network volume, and matrix permeation volume during the fracturing process of each oil well in Table 4, the proportion of the average single-well injected fluid volume in each volume (wellbore, main fracture, secondary fracture network, and matrix permeation) can be calculated. Analysis of the proportion of injected fluid volume in each volume (wellbore, main fracture, secondary fracture network, and matrix permeation) during the fracturing process of 55 horizontal wells in the field shows that the matrix permeation volume accounts for the largest proportion (reaching 87.57%), revealing the key role of fracturing fluid permeation and replacement in the development of tight reservoirs, and reasonably explaining the generally low flowback rate in tight reservoirs. The second largest proportion is the secondary fracture network volume (11.12%), indicating that in addition to its important role in permeation and replacement for oil production, the injected fracturing fluid also plays another major role in carrying sand and creating complex fracture networks. The wellbore volume (only 1.02%) and main fracture volume (only 1.29%) account for a relatively small proportion.

[0134] (2) Sensitivity analysis of volumetric fracturing effect in unconventional reservoirs. A single-factor analysis method was used to evaluate the influence of different total fracturing fluid injection volumes and different number of fracturing stages in horizontal wells on the effective fracture network length, single-stage fracture network stimulation volume, single-stage fracture network permeation volume and equivalent permeation depth, providing a convenient chart for quantitative evaluation of the volumetric fracturing effect in actual blocks;

[0135] Reference Figures 5-8 Based on the aforementioned evaluation model and solution method for unconventional reservoir volumetric fracturing effect, a single-factor analysis method was used to obtain multiple sets of theoretical curves for effective fracture network length, single-segment fracture network stimulation volume, single-segment fracture network permeation volume, and equivalent permeation depth under different total fracturing fluid injection volumes and different horizontal well fracturing stages. This provides engineering technicians with convenient reference charts for quantitative evaluation of the volumetric fracturing effect in actual blocks.

[0136] (3) Quantitative evaluation of the volumetric fracturing effect in unconventional reservoirs. Based on the volumetric fracturing construction of typical well groups in the target reservoir of the study area at different well network development stages, the length and width of the fracture network in the volumetric fracturing section of each horizontal well were quantitatively calculated. Based on the three-dimensional spatial distribution of the well network and fracture network, the overlap relationship between the volumetric fracturing fracture networks of each well was determined, and the volumetric fracturing effect of the target reservoir in the study area at different well network development stages was quantitatively evaluated.

[0137] Reference Figures 9-11 Evaluation results of volumetric fracturing effects in typical well groups of the target reservoir in the study area show that: for the basic well network, the volumetric fracturing network of a single well is isolated, the overlap between the fracture networks is poor, the matching degree between the well network and the fracture network is low, and the utilization rate of the block reserves is only 21.31%; for the first-stage infill well network, the volumetric fracturing network of a single well is relatively isolated, the overlap between the fracture networks is poor, the well network and the fracture network still cannot be matched, and the utilization rate of the block reserves is 32.25%; while for the second-stage infill well network, there are almost no isolated areas of volumetric fracturing network of a single well, the overlap between the fracture networks is good, the matching degree between the well network and the fracture network is high, and the utilization rate of the block reserves can reach 83.65%.

[0138] The above description is merely a preferred embodiment of the present invention. The numerical values ​​and ranges mentioned in the above specification are not intended to limit the present invention, but only to provide preferred embodiments. Various modifications and variations can be made to the present invention by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.

Claims

1. A method for evaluating the effectiveness of unconventional reservoir volumetric fracturing based on material balance, characterized in that, Includes the following steps: Step 1: Establish the material balance equations for unconventional reservoir volumetric fracturing. Based on the principle of mass conservation in the fracturing injection fluid system, a material balance equation for unconventional reservoir volume fracturing is established. The total amount of fracturing fluid injected includes: wellbore volume, main fracture pore volume, secondary fracture network pore volume, and matrix pore volume near the entire fracture network. A calculation model for the above four volumes is established. Material balance equations for the seepage process, elastically driven material balance equations and state equations are also established. The calculation model for the matrix pore adsorption volume near the entire fracture network is expressed as follows: In the formula: V m V represents the volume of infiltration in the matrix pores; d represents the equivalent infiltration depth; φ1 represents the porosity of the formation rock after the infiltration process ends; V f The main fracture pore volume is r, which is the ratio of the longitudinal and transverse lengths of the fractures in a single-stage fracturing network; x f The main fracture half-length; H is the target reservoir thickness in the study area; The mass balance equation for the adsorption process is as follows: In the formula: S oi 、S or These represent the initial oil saturation of the core before infiltration begins and the residual oil saturation of the core after infiltration ends; R o Core permeation recovery rate; Step 2: Solving and Verifying the Material Balance Equation for Volumetric Fracturing Based on the actual geological, fluid, and rock mechanics parameters of the target reservoir in the study area, and combined with oil well fracturing data, the established set of unconventional reservoir volume fracturing material balance equations were solved simultaneously. At the same time, the effective support length of the fracturing fracture, the equivalent penetration depth, the average formation pressure after penetration, and the average formation pressure after fracturing flowback were obtained for each oil well. The reliability of the above material balance equations was verified based on the actual development of typical well groups. Step 3: Quantitative Evaluation of the Effect of Volumetric Fracturing in Unconventional Reservoirs The effective supported fracture length and equivalent permeation depth were obtained by solving the unconventional reservoir volumetric fracturing material balance equation. The wellbore volume, main fracture volume, secondary fracture network volume, and secondary fracture network permeation volume were calculated respectively to obtain the proportion of injected fluid volume in each of the wellbore, main fracture, secondary fracture network, and matrix permeation volumes during the volumetric fracturing process. Sensitivity analysis of the volumetric fracturing effect was conducted to obtain the influence of different total injection volumes of fracturing fluid and different numbers of fracturing stages on the volumetric fracturing fracture network parameters. Based on the volumetric fracturing construction of typical well groups in the target reservoir of the study area at different well network development stages, the volumetric fracturing effect of the target reservoir at different well network development stages was quantitatively evaluated.

2. The method for evaluating the effect of unconventional reservoir volumetric fracturing based on material balance according to claim 1, characterized in that, The specific steps of step one are as follows: (1) Establish a physical model for the propagation of the volumetric fracturing fracture network in unconventional reservoirs and its assumptions; (2) Establish a wellbore volume calculation model. (3) Establish a calculation model for the pore volume of the main fracture; (4) Establish a calculation model for the pore volume of the secondary fracture network; In the formula: V s x represents the pore volume of the secondary fracture network. f The main fracture half-length is half the effective support length of the fracturing fracture, i.e., half the major axis of the elliptical physical model; w f λ represents the width of the primary fracture; H represents the thickness of the target reservoir in the study area; λ represents the ratio of the width of the primary fracture to the width of the secondary fracture; M represents the length of the target reservoir segment; and N represents the number of natural fractures. (5) Establish a calculation model for the volume of matrix pores near the entire fracture network; then establish the material balance equation for the infiltration process. (6) Establish the relationship between the injection volume of fracturing fluid and the changes in formation pressure and underground pore volume after the fracturing fluid has undergone the seepage effect, and the relationship between the surface production of oil wells and the changes in formation pressure and underground pore volume during the fracturing flowback period. These are used as the material balance equations for the reservoir elastic drive during the fracturing flowback period. State equations related to pore volume changes before fracturing, after seepage and after flowback are given. Finally, an unconventional reservoir volume fracturing material balance equation set is formed, which is an unconventional reservoir volume fracturing effect evaluation model based on material balance.

3. The method for evaluating the effect of unconventional reservoir volumetric fracturing based on material balance according to claim 2, characterized in that, The relationship between the injection volume of fracturing fluid and the changes in formation pressure and underground pore volume after the fracturing fluid has undergone its absorption effect is as follows: Q i -V w -m(V f +V s )=V c1 (1-s wc )(c o +c c )(p1-p i ) In the formula: Q i c is the fracturing fluid injection volume for a single section of a horizontal well; o c is the crude oil compressibility coefficient. c p is the compressibility coefficient of the reservoir volume; p1 is the mean formation pressure after the end of the seepage process; p i V represents the mean pressure of the original formation. c1 V is the reservoir pressure swept volume after the infiltration process ends, expressed as V c1 =4x f (L+S)Hφ1, where: S is the horizontal well spacing; φ1 is the porosity of the formation rock after the end of the seepage process; V w The volume of the wellbore is represented by m; the number of fracturing stages in the well is represented by m. The relationship between the surface fluid production of the oil well during the fracturing flowback period and the changes in formation pressure and underground pore volume is as follows: N p B o +W p B w +V w +m(V f +V s )=V c2 (c o +c c )(p1-p2-p l ) Where: N p Cumulative oil production during the return period; W p B represents the cumulative water production during the return flow period. o B is the crude oil volume coefficient; w p1 is the formation water volume factor; p2 is the average formation pressure after fracturing and flowback; p l The pressure loss of the fluid in the wellbore is expressed as p. l =0.0028h, where: h is the wellbore depth; V c2 V is the reservoir pressure swept volume after fracturing and flowback, expressed as V c2 =4x f (L+S)Hφ2, where: φ2 is the porosity of the formation rock after the hydraulic fracturing and flowback are completed.

4. The method for evaluating the effect of unconventional reservoir volumetric fracturing based on material balance according to claim 1, characterized in that, The specific steps of step two are as follows: (1) Basic data preparation; Based on the existing geological development characteristics research results of the target reservoir in the study area, the reservoir geological characteristic parameters, formation rock mechanical parameters, fracturing construction parameters of each well and production dynamic data statistics during the flowback period were compiled. (2) Solving the evaluation model of unconventional reservoir volumetric fracturing effect based on material balance; Based on the unconventional reservoir volumetric fracturing material balance equation set and the closed equation characteristics of the four unknowns established in step one, the calculation process is designed and a multi-well synchronous solution program is compiled. Finally, the key evaluation parameters of each oil well are obtained, including: effective support length of fracturing fracture, equivalent permeation depth, formation average pressure after permeation and formation average pressure after fracturing flowback. The volumes of each part are further calculated, including wellbore volume, main fracture volume, secondary fracture network volume and matrix permeation volume. (3) Verification of the reliability of the solution results of the material balance equation for unconventional reservoir volume fracturing: Based on the microseismic monitoring data of the fracturing wells in the field and the actual well spacing and development dynamics, the reliability of the solution results of the above material balance equation is comprehensively verified.

5. The method for evaluating the effect of unconventional reservoir volumetric fracturing based on material balance according to claim 1, characterized in that, The specific steps of step three are as follows: (1) The effective support fracture length and equivalent permeation depth obtained by solving the unconventional reservoir volumetric fracturing material balance equation set were used to calculate the wellbore volume, main fracture volume, secondary fracture network volume and secondary fracture network permeation volume respectively. The proportion of the injected fluid volume in each part of the wellbore volume, main fracture volume, secondary fracture network volume and matrix permeation volume during the volumetric fracturing process was obtained, revealing the key role of fracturing fluid permeation and replacement in the development of unconventional reservoirs. (2) Sensitivity analysis of volumetric fracturing effect in unconventional reservoirs: Using a single-factor analysis method, the influence of different total fracturing fluid injection volume and different number of horizontal well fracturing stages on the effective fracture network length, single-section fracture network stimulation volume, single-section fracture network permeation volume and equivalent permeation depth is evaluated, providing a convenient chart for quantitative evaluation of the volumetric fracturing effect in actual blocks. (3) Quantitative evaluation of the volumetric fracturing effect of unconventional reservoirs: Based on the volumetric fracturing construction of typical well groups in the target reservoir of the study area at different well network development stages, the length and width of the fracture network in the volumetric fracturing section of each horizontal well are quantitatively calculated. Based on the plane distribution of the well network and the fracture network, the overlap relationship between the volumetric fracturing fracture networks of each well is determined, and the volumetric fracturing effect of the target reservoir of the study area at different well network development stages is quantitatively evaluated.

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