OPTIMIZATION METHOD FOR DENSE CUTTING, TEMPORARY PLUGGING AND FRACTURING IN SHALE HORIZONTAL WELL STAGE

Abstract

Disclosed is an optimization method for dense cutting, temporary plugging and fracturing in shale horizontal well stage. The optimization method includes steps of obtaining reservoir parameters, completion parameters, and fracturing construction parameters, establishing a fluid-solid coupling model of hydraulic fracturing through a discontinuous displacement method, establishing a fracture propagation model for dense cutting, temporary plugging and fracturing in shale horizontal well stage, calculating geometric parameters of dense cutting, temporary plugging and fracturing fractures in shale horizontal well stage based on the reservoir parameters, the completion parameters, and the fracturing construction parameters, optimizing the construction parameters of dense cutting, temporary plugging and fracturing in shale horizontal well stage based on the geometric parameters of hydraulic fractures after dense cutting, temporary plugging and fracturing in stage and results temporary plugging operations.

Claims

1. An optimization method for dense cutting, temporary plugging and fracturing in shale horizontal well stage, comprising: S10: obtaining reservoir parameters, completion parameters, and fracturing construction parameters; S20: establishing a fluid-solid coupling model of hydraulic fracturing through a discontinuous displacement method; S30: establishing a fracture propagation model for dense cutting, temporary plugging and fracturing in shale horizontal well stage; S40: calculating geometric parameters of dense cutting, temporary plugging and fracturing fractures in shale horizontal well stage based on the reservoir parameters, the completion parameters, and the fracturing construction parameters; S50: optimizing the construction parameters of dense cutting, temporary plugging and fracturing in shale horizontal well stage based on results of fracture extension and temporary plugging operations.

2. The optimization method of claim 1, wherein a flow field model of the fluid-solid coupling model of hydraulic fracturing in the step S20 is: $\{\begin{array}{c}{p}_{\mathrm{pf}}=\frac{0.2369{\rho }_s}{n^2{d}^4{c}^2}{Q}_c^2\\ \frac{\partial p}{\partial s}=2^{n^{\prime }+1}{k^{\prime }\left(\frac{1+2n^{\prime }}{n^{\prime }}\right)}^{n^{\prime }}{h}^{-n^{\prime }}{w}^{-\left(2n^{\prime }+1\right)}{Q}^{n^{\prime }}\end{array}\underset{0}{\overset{t}{\int }}{Q}_T\left(t\right)\mathrm{dt}=\underset{i=1}{\overset{N}{.Math.}}\underset{0}{\overset{L_i\left(t\right)}{\int }}\mathrm{hwds}+\underset{i}{\overset{N}{.Math.}}\underset{0}{\overset{L_i\left(t\right)}{\int }}\underset{0}{\overset{t}{\int }}\frac{2C_L}{\sqrt{t-\tau \left(s\right)}}\mathrm{dtds}$ wherein, Q.sub.c is the flow rate of fracturing fluid through a perforation; Q is the fracturing fluid flow rate inside the hydraulic fracture; Q.sub.T is the total fracturing fluid flow rate during fracturing construction process; p.sub.pf is the friction at a horizontal wellbore perforation; p is the flow friction of the fracturing fluid in hydraulic fractures; n′ is the fluid power law exponent; k′ is the fluid viscosity index; ρ.sub.s is fracturing fluid density; n is the number of perforations; d is perforation diameter; c is flow coefficient; L is the fracture length of the hydraulic fracture; h is the fracture height of the hydraulic fracture; w is fracture width of the hydraulic fracture; N is the number of the hydraulic fractures; C.sub.L is fluid loss coefficient for the fracturing fluid; t is current fracturing construction time; τ is fracture opening time; a stress field model of the fluid-solid coupling model of hydraulic fracturing in the step S20 is: $\{\begin{array}{c}{\stackrel{i}{\sigma }}_s=\underset{j=1}{\overset{N}{.Math.}}{T}^{\mathrm{ij}}{\stackrel{\mathrm{ij}}{A}}_{\mathrm{ss}}{\stackrel{j}{D}}_s+\underset{j=1}{\overset{N}{.Math.}}{T}^{\mathrm{ij}}{\stackrel{\mathrm{ij}}{A}}_{\mathrm{sn}}{\stackrel{j}{D}}_n\\ {\stackrel{i}{\sigma }}_n=\underset{j=1}{\overset{N}{.Math.}}{T}^{\mathrm{ij}}{\stackrel{\mathrm{ij}}{A}}_{\mathrm{ns}}{\stackrel{j}{D}}_s+\underset{j=1}{\overset{N}{.Math.}}{T}^{\mathrm{ij}}{\stackrel{\mathrm{ij}}{A}}_{\mathrm{nn}}{\stackrel{j}{D}}_n\end{array}{T}^{\mathrm{ij}}=1-\frac{d_{\mathrm{ij}}^3}{{\left[d_{\mathrm{ij}}^2+{\left(h\text{/}2\right)}^2\right]}^{1.5}}$ in the formula, N is a total number of hydraulic fracture unit; .sup.ijA is a boundary strain influence coefficient matrix, describing a influence of a displacement discontinuity of the j-th fracture unit on a stress of the i-th fracture unit; σ.sup.i is a stress generated at the i-th fracture unit by the displacement discontinuity of the j-th fracture unit; σ.sub.s and σ.sub.n respectively are the tangential and normal stress along the fracture unit; D.sub.s and D.sub.n respectively are the discontinuity of the tangential and normal displacement of the fracture unit; T.sup.ij is a fracture height correction coefficient, used for correction the influence of the fracture height in the two-dimensional fracture model; h is a fracture height; d.sub.ij is a distance between the midpoint of the i-th fracture unit and the j-th fracture unit.

3. The optimization method of claim 1, where in the fracture propagation model for dense cutting, temporary plugging and fracturing in shale horizontal well stage in the step S30 is: $K_e=\frac{1}{2}\cos \left(\frac{\alpha }{2}\right)\left[K_I\left(1+\cos \left(\alpha \right)\right)-3K_{\mathrm{II}}\sin \left(\alpha \right)\right]$ $\{\begin{array}{c}{K}_I=\frac{0.806E\sqrt{\pi }}{4\left(1-v^2\right)\sqrt{2a}}{D}_n^{\mathrm{Tip}}\\ K_{\mathrm{II}}=\frac{0.806E\sqrt{\pi }}{4\left(1-v^2\right)\sqrt{2a}}{D}_s^{\mathrm{Tip}}\end{array}\{\begin{array}{c}{\sigma }_{\mathrm{xx}}={\sigma }_H-\frac{K_I}{\sqrt{2\pi r}}\cos \frac{\theta }{2}\left(1-\sin \frac{\theta }{2}\sin \frac{3\theta }{2}\right)+\frac{K_{\mathrm{II}}}{\sqrt{2\pi r}}\sin \frac{\theta }{2}\left(2+\cos \frac{\theta }{2}\cos \frac{3\theta }{2}\right)\\ {\sigma }_{\mathrm{yy}}={\sigma }_H-\frac{K_I}{\sqrt{2\pi r}}\cos \frac{\theta }{2}\left(1+\sin \frac{\theta }{2}\sin \frac{3\theta }{2}\right)-\frac{K_{\mathrm{II}}}{\sqrt{2\pi r}}\sin \frac{\theta }{2}\cos \frac{\theta }{2}\cos \frac{3\theta }{2}\\ {\tau }_{\mathrm{xy}}=0-\frac{K_I}{\sqrt{2\pi r}}\sin \frac{\theta }{2}\cos \frac{\theta }{2}\cos \frac{3\theta }{2}-\frac{K_{\mathrm{II}}}{\sqrt{2\pi r}}\cos \frac{\theta }{2}\left(1-\sin \frac{\theta }{2}\sin \frac{3\theta }{2}\right)\end{array}\{\begin{array}{c}{\sigma }_r=\frac{{\sigma }_{\mathrm{xx}}+{\sigma }_{\mathrm{yy}}}{2}+\frac{{\sigma }_{\mathrm{xx}}-{\sigma }_{\mathrm{yy}}}{2}\cos 2\theta +{\tau }_{\mathrm{xy}}\sin 2\theta \\ {\sigma }_{\theta }=\frac{{\sigma }_{\mathrm{xx}}+{\sigma }_{\mathrm{yy}}}{2}-\frac{{\sigma }_{\mathrm{xx}}-{\sigma }_{\mathrm{yy}}}{2}\cos 2\theta -{\tau }_{\mathrm{xy}}\sin 2\theta \\ {\tau }_{r\theta }={\tau }_{\mathrm{xy}}\cos 2\theta -\frac{{\sigma }_{\mathrm{xx}}-{\sigma }_{\mathrm{yy}}}{2}\sin 2\theta \end{array}{p}_{\mathrm{nf}}>{\sigma }_{\mathrm{nf}}+{\sigma }_T.Math.{\tau }_{\mathrm{nf}}.Math.>{\tau }_0+K_f\left({\sigma }_{\mathrm{nf}}-p_{\mathrm{nf}}\right)$ wherein, K.sub.e is an equivalent stress intensity factor; α is an angle of the fracture unit; E is Young's modulus; v is Poisson's ratio; α is a half-length of the fracture unit; D.sub.n.sup.Tip and D.sub.s.sup.Tip respectively are the discontinuous quantity of normal and shear displacements of a fracture tip unit; σ.sub.xx, σ.sub.yy and τ.sub.xy respectively are a stress field at a natural fracture caused by induced stress and in-situ stress in the Cartesian coordinate system; σ.sub.r, σ.sub.θ and τ.sub.rθ respectively are a stress field at a natural fracture in the polar coordinate system established by transforming from σ.sub.xx, σ.sub.yy and τ.sub.xy to taking a contact point as a origin point; σ.sub.H and σ.sub.h are the maximum and minimum horizontal principal stresses of the shale reservoir respectively; r is the polar diameter in the polar coordinate system; θ is the approach angle between hydraulic fractures and natural fracture; K.sub.I and K.sub.II respectively are type I (tension type) and type II (shear type) stress intensity factor; p.sub.nf is the fluid pressure at the intersection of hydraulic fractures and natural fractures; σ.sub.nf and σ.sub.nf respectively are the normal and tangential stress on a natural fracture wall; σ.sub.T and τ.sub.0 respectively are a tensile and shear strength of the natural fracture; K.sub.f is a friction coefficient of the natural fracture wall.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0014] FIG. 1 is a flow chart of solving the fracture propagation model for dense cutting, temporary plugging and optimizing construction parameters.

[0015] FIG. 2 is a schematic diagram of natural fracture distribution.

[0016] FIG. 3 is a fracturing fluid flow model during dense cutting, temporary plugging and fracturing.

[0017] FIG. 4 is a schematic diagram of hydraulic fracture approaching natural fracture.

[0018] FIG. 5 is a simulation result of five clusters of fractures with dense cutting, temporary plugging and fracturing fracture propagation under a displacement of 12 m.sup.3/min.

[0019] FIG. 6 is a simulation result of five clusters of fractures with dense cutting, temporary plugging and fracturing fracture propagation under a displacement of 14 m.sup.3/min.

[0020] FIG. 7 is a simulation result of seven clusters of fractures with dense cutting, temporarily plugging and fracturing fracture propagation under a displacement of 12 m.sup.3/min.

[0021] FIG. 8 is a simulation result of seven clusters of fractures with dense cutting, temporary plugging and fracturing fracture propagation under a displacement of 14 m.sup.3/min.

[0022] FIG. 9 is a simulation result of seven clusters of fractures with dense cutting, temporary plugging and fracturing fracture propagation under a displacement of 16 m.sup.3/min.

DETAILED DESCRIPTION OF EMBODIMENTS

[0023] According to the description of the content of the disclosure, the construction displacement in the construction parameters is taken as an example of the optimization target parameters, and the disclosure is further described by the first embodiment, the second embodiment and the drawings.

Embodiment 1

[0024] Referring to FIG. 1, the main content of the disclosure is an optimization method for dense cutting, temporary plugging and fracturing in shale horizontal well stage, and the main steps include:

[0025] S10: obtaining reservoir parameters, completion parameters, and fracturing construction parameters.

[0026] Among them, the reservoir parameters include reservoir thickness, Young's modulus, shear modulus, Poisson's ratio, horizontal maximum principal stress, horizontal minimum principal stress, fracture toughness of reservoir rock and the average length, angle, density, tensile strength, shear strength, fracture surface friction coefficient, etc. of natural fractures; the completion parameters include perforation cluster number, perforation number and perforation diameter; the construction parameters include fracturing fluid rheological parameters, construction displacement, etc. To illustrate the optimization method of the disclosure, Embodiment 1 uses the relevant geological parameters of a shale reservoir in Well Y in a certain block of Jianghan Oilfield. Referring to Table 1, natural fractures are randomly generated, and the distribution diagram is shown in FIG. 2.

TABLE-US-00001 TABLE 1 parameter unit value horizontal maximum principal stress MPa 58.0 horizontal minimum principal stress MPa 52.0 Young's modulus MPa 37.5 Poisson's ratio — 0.20 reservoir thickness m 50.0 fluid loss coefficient m/min.sup.0.5 3.0 × 10.sup.−4 fracturing fluid density kg/m3 1.0 × 10.sup.3  fracturing fluid flux m.sup.3/min 12 fluid power law exponent — 1.0 fluid viscosity index mPa .Math. s.sup.n′ 1.0 rock toughness MPa .Math. m.sup.0.5 1.2 perforation number — 16 perforation diameter m 0.012 perforation cluster number — 5 cluster spacing m 10 tensile strength of natural fracture MPa 1.0 shear strength of natural fracture MPa 1.9 fracture surface friction coefficient of — 0.32 natural fracture approach angle ° 60 average fracture length of natural m 8 fracture

[0027] S20: establishing a fluid-solid coupling model of hydraulic fracturing through a displacement discontinuity method.

[0028] The fracturing fluid flow model during the dense cutting, temporary plugging and fracturing process in a horizontal well stage is shown in FIG. 3, which mainly includes the flow of fracturing fluid thorough the perforation and the flow of fracturing fluid in hydraulic fractures. The flow field model in fluid-solid coupling is:

[00004]$\{\begin{array}{c}{p}_{\mathrm{pf}}=\frac{0.2369{\rho }_s}{n^2{d}^4{c}^2}{Q}_c^2\\ \frac{\partial p}{\partial s}=2^{n^{\prime }+1}{k^{\prime }\left(\frac{1+2n^{\prime }}{n^{\prime }}\right)}^{n^{\prime }}{h}^{-n^{\prime }}{w}^{-\left(2n^{\prime }+1\right)}{Q}^{n^{\prime }}\end{array}\underset{0}{\overset{t}{\int }}{Q}_T\left(t\right)\mathrm{dt}=\underset{i=1}{\overset{N}{.Math.}}\underset{0}{\overset{L_i\left(t\right)}{\int }}\mathrm{hwds}+\underset{i}{\overset{N}{.Math.}}\underset{0}{\overset{L_i\left(t\right)}{\int }}\underset{0}{\overset{t}{\int }}\frac{2C_L}{\sqrt{t-\tau \left(s\right)}}\mathrm{dtds}$

[0029] In the formula, Q.sub.c is fracturing fluid fluxthrough thr perforation; Q is a fracturing fluidflux inside the hydraulic fracture; Q.sub.T is a total fracturing fluid flow during fracturing construction process; p.sub.pf is the friction at a horizontal wellbore perforation; p is a flow friction of the fracturing fluid in hydraulic fractures; n′ is a fluid power law exponent; k′ is a fluid viscosity index; ρ.sub.s is fracturing fluid density; n is the number of perforations; d is the perforation diameter; c is the flow coefficient; L is the fracture length of the hydraulic fracture; h is the fracture height of the hydraulic fracture; w is fracture width of the hydraulic fracture; N is the number of the hydraulic fractures; C.sub.L is thefluid loss coefficient for the fracturing fluid; t is the current fracturing construction time; τ is a fracture opening time.

[0030] Among them, based on the discontinuous displacement method, the stress field model in the fluid-solid coupling model is:

[00005]$\{\begin{array}{c}{\stackrel{i}{\sigma }}_s=\underset{j=1}{\overset{N}{.Math.}}{T}^{\mathrm{ij}}{\stackrel{\mathrm{ij}}{A}}_{\mathrm{ss}}{\stackrel{j}{D}}_s+\underset{j=1}{\overset{N}{.Math.}}{T}^{\mathrm{ij}}{\stackrel{\mathrm{ij}}{A}}_{\mathrm{sn}}{\stackrel{j}{D}}_n\\ {\stackrel{i}{\sigma }}_n=\underset{j=1}{\overset{N}{.Math.}}{T}^{\mathrm{ij}}{\stackrel{\mathrm{ij}}{A}}_{\mathrm{ns}}{\stackrel{j}{D}}_s+\underset{j=1}{\overset{N}{.Math.}}{T}^{\mathrm{ij}}{\stackrel{\mathrm{ij}}{A}}_{\mathrm{nn}}{\stackrel{j}{D}}_n\end{array}{T}^{\mathrm{ij}}=1-\frac{d_{\mathrm{ij}}^3}{{\left[d_{\mathrm{ij}}^2+{\left(h\text{/}2\right)}^2\right]}^{1.5}}$

[0031] In the formula, N is a total number of hydraulic fracture elements; .sup.ijA is the boundary strain influence coefficient matrix, describing the influence of a displacement discontinuity of the jth fracture unit on a stress of the i-th fracture unit; τ.sup.i is the stress generated at the ith fracture element by the displacement discontinuity of the jth fracture element; σ.sub.s and σ.sub.n respectively is the tangential and normal stress along the fracture element; D.sub.s and D.sub.n respectively are the discontinuity of the tangential and normal displacement of the fracture unit; T.sup.ij is a fracture height correction coefficient, used for correction the influence of the fracture height in the two-dimensional fracture model; h is fracture height; d.sub.ij is the distance between the midpoint of the ith fracture unit and the jth fracture unit.

[0032] S30: establishing a fracture propagation model for dense cutting, temporary plugging and fracturing in shale horizontal well stage.

[0033] When the hydraulic fracture is not approach to the natural fracture, the fracture propagation criterion is the maximum circumferential stress criterion. By calculating the equivalent stress intensity factor K.sub.e of the fracture tip unit, when the K.sub.e value is greater than the fracture toughness of the rock, the fracture propagates.

[00006]$K_e=\frac{1}{2}\cos \left(\frac{\alpha }{2}\right)\left[K_I\left(1+\cos \left(\alpha \right)\right)-3K_{\mathrm{II}}\sin \left(\alpha \right)\right]$$\{\begin{array}{c}{K}_I=\frac{0.806E\sqrt{\pi }}{4\left(1-v^2\right)\sqrt{2a}}{D}_n^{\mathrm{Tip}}\\ K_{\mathrm{II}}=\frac{0.806E\sqrt{\pi }}{4\left(1-v^2\right)\sqrt{2a}}{D}_s^{\mathrm{Tip}}\end{array}$

[0034] In the formula, K.sub.e is an equivalent stress intensity factor; α is an angle of the fracture unit; E is Young's modulus; v is Poisson's ratio; a is a half-length of the fracture unit; D.sub.n.sup.Tip and D.sub.s.sup.Tip respectively are discontinuous quantity of normal and shear displacements of a fracture tip unit; K.sub.I and K.sub.II respectively are type I (tension type) and type II (shear type) stress intensity factor.

[0035] When the hydraulic fracture approaches the natural fracture, the schematic diagram of the interaction between the two is shown in FIG. 4. The combined stress field of the induced stress generated by the hydraulic fracture and the in-situ stress on the natural fracture wall is:

[00007]$\{\begin{array}{c}{\sigma }_{\mathrm{xx}}={\sigma }_H-\frac{K_I}{\sqrt{2\pi r}}\cos \frac{\theta }{2}\left(1-\sin \frac{\theta }{2}\sin \frac{3\theta }{2}\right)+\frac{K_{\mathrm{II}}}{\sqrt{2\pi r}}\sin \frac{\theta }{2}\left(2+\cos \frac{\theta }{2}\cos \frac{3\theta }{2}\right)\\ {\sigma }_{\mathrm{yy}}={\sigma }_H-\frac{K_I}{\sqrt{2\pi r}}\cos \frac{\theta }{2}\left(1+\sin \frac{\theta }{2}\sin \frac{3\theta }{2}\right)-\frac{K_{\mathrm{II}}}{\sqrt{2\pi r}}\sin \frac{\theta }{2}\cos \frac{\theta }{2}\cos \frac{3\theta }{2}\\ {\tau }_{\mathrm{xy}}=0-\frac{K_I}{\sqrt{2\pi r}}\sin \frac{\theta }{2}\cos \frac{\theta }{2}\cos \frac{3\theta }{2}-\frac{K_{\mathrm{II}}}{\sqrt{2\pi r}}\cos \frac{\theta }{2}\left(1-\sin \frac{\theta }{2}\sin \frac{3\theta }{2}\right)\end{array}\hspace{1em}$

[0036] In the formula, a.sub.xx, σ.sub.yy and τ.sub.xy respectively is a stress field at a natural fracture caused by induced stress and in-situ stress in the Cartesian coordinate system; σ.sub.H and σ.sub.h are the maximum and minimum horizontal principal stresses of the shale reservoir respectively; r is the polar diameter in the polar coordinate system; θ is the approach angle between hydraulic fractures and natural fracture.

[0037] The stress field in the above rectangular coordinate system is transformed into a polar coordinate system established with the contact point of the hydraulic fracture and the natural fracture as the origin. The stress field at the natural fracture is:

[00008]$\{\begin{array}{c}{\sigma }_r=\frac{{\sigma }_{\mathrm{xx}}+{\sigma }_{\mathrm{yy}}}{2}+\frac{{\sigma }_{\mathrm{xx}}-{\sigma }_{\mathrm{yy}}}{2}\cos 2\theta +{\tau }_{\mathrm{xy}}\sin 2\theta \\ {\sigma }_{\theta }=\frac{{\sigma }_{\mathrm{xx}}+{\sigma }_{\mathrm{yy}}}{2}-\frac{{\sigma }_{\mathrm{xx}}-{\sigma }_{\mathrm{yy}}}{2}\cos 2\theta -{\tau }_{\mathrm{xy}}\sin 2\theta \\ {\tau }_{r\theta }={\tau }_{\mathrm{xy}}\cos 2\theta -\frac{{\sigma }_{\mathrm{xx}}-{\sigma }_{\mathrm{yy}}}{2}\sin 2\theta \end{array}\hspace{1em}$

[0038] In the formula, σ.sub.r, σ.sub.θ and τ.sub.rθ respectively are stress field at a natural fracture in the polar coordinate system established by transforming from σ.sub.xx, σ.sub.yy and τ.sub.xy to taking a contact point as a origin point.

[0039] When the hydraulic fracture is approaching the natural fracture, the criterion for judging the hydraulic fracture passing through the natural fracture is:

p.sub.nf>σ.sub.nf+σ.sub.T

[0040] In the inequality, p.sub.nf is the fluid pressure at the intersection of the hydraulic fracture and the natural fracture; σ.sub.nf is the normal stress on the wall of the natural fracture; UT is the tensile strength of the natural fracture.

[0041] When the hydraulic fracture is approaching the natural fractures, the criteria for judging the hydraulic fracture along the natural fracture is:

|τ.sub.nf|>τ.sub.0+K.sub.f(σ.sub.nf−p.sub.nf)

[0042] In the inequality, τ.sub.nf is the tangential stress on the wall of the natural fracture; τ.sub.0 is the shear strength of the natural fracture; K.sub.f is the friction coefficient of the wall of the natural fracture.

[0043] S40: calculating geometric parameters of dense cutting, temporary plugging and fracturing fractures in shale horizontal well stage based on the reservoir parameters, the completion parameters, and the fracturing construction parameters.

[0044] Under the condition of a construction rateo 12 m.sup.3/min, five clusters of hydraulic fractures are subjected to dense cutting, tempor ary plugging and fracturing fracture propagation numerical at various stages. Referring to FIG. 5, the simulation result includes the fracture geometry distribution results from three different stages of temporary plugging, including no temporary plugging, the first temporary plugging, and the second temporary plugging.

[0045] S50: optimizing the construction parameters of dense cutting, temporary plugging and fracturing in shale horizontal well stage based on results of fracture extension and temporary plugging operations.

[0046] When the displacement is 12 m.sup.3/min, the completion of the temporary plugging and fracturing of five clusters of fractures requires two temporary plugging operations, and the fracture width obtained after the second operation is relatively low. In order to reduce the number of temporary plugging operations, increase the success rate of fracturing operations, and increase the fracture width after fracturing, the construction parameters need to be optimized and adjusted. Now increase the construction displacement to 14 m.sup.3/min, and the results obtained after the numerical simulation of dense cutting, temporary plugging and fracturing fracture propagation are shown in FIG. 6, including the fracture geometry morphological distribution results at two different stages of no temporary plugging and the first temporary plugging. It can be found that after increasing the displacement, the number of temporary plugging operations decreases, the number of uniform fracture propagations in the non-temporary plugging phase increases, and the average fractures width increases. Therefore, based on the above simulation parameters, for the dense cutting, temporary plugging and fracturing of five clusters of fractures, to reduce the number of temporary plugging operations and increase the average fracture width of the fractures, the construction displacement should be maintained at 14 m.sup.3/min and above after optimization.

Embodiment 2

[0047] In order to further illustrate the optimization method of the disclosure, the construction displacement is still used as an optimization parameter, and the embodiment 2 is modified on the basis of the embodiment 1 to increase the number of fractures clusters from five clusters to seven clusters, and perform construction displacement optimization of dense cutting, temporary plugging and fracturing.

[0048] S10: obtaining reservoir parameters, completion parameters, and fracturing construction parameters.

[0049] The parameters in the Embodiment 2 are as shown in Table 1. Only the number of fracture clusters is changed to seven clusters, the distribution of natural fractures does not change, and the distribution pattern in FIG. 2 is still adopted.

[0050] S20: establishing a fluid-solid coupling model of hydraulic fracturing through a displacement discontinuity method.

[0051] Under the condition of seven clusters of fractures, the process of establishing a fluid-solid coupling model for dense cutting, temporary plugging and fracturing in horizontal well is consistent with the process in Embodiment 1.

[0052] S30: establishing a fracture propagation model for dense cutting, temporary plugging and fracturing in shale horizontal well stage.

[0053] Under the condition of seven clusters of fractures, the fracture propagation model for dense cutting, temporary plugging and fracturing in shale horizontal well stage does not change, which is the same as the propagation model in the Embodiment 1.

[0054] S40: calculating geometric parameters of dense cutting, temporary plugging and fracturing fractures in shale horizontal well stage based on the reservoir parameters, the completion parameters, and the fracturing construction parameters.

[0055] Under the condition of a construction displacement of 12 m.sup.3/min, seven clusters of hydraulic fractures are subjected to dense cutting, temporary plugging and fracturing fracture propagation numerical at various stages. Referring to FIG. 7, the simulation result includes the fracture geometry distribution results from four different stages of temporary plugging, including no temporary plugging, the first temporary plugging, the second temporary plugging, and the third temporary plugging.

[0056] S50: optimizing the construction parameters of dense cutting, temporary plugging and fracturing in shale horizontal well stage based on results of fracture extension and temporary plugging operations.

[0057] Under the condition of a construction flow rate of 12 m.sup.3/min, three temporary plugging operations are required to complete the temporary plugging and fracturing of seven clusters of fractures, and the number of temporary plugging is greater than that of five clusters of fractures. At this flow rate, except for the remaining one cluster of fractures propagation after the third temporary plugging operation, there are only two symmetrical propagation of fractures in the rest of the state, indicating that the simultaneous propagation of two more fractures cannot be achieved under this displacement. Because there are multiple hydraulic fractures in a single stage, the hydraulic fractures formed by the first propagation will have a strong inter-fracture interference effect on the hydraulic fractures formed by the later propagation, so that the average fracture width of the hydraulic fractures obtained by the dense cutting, temporary plugging and fracturing at this displacement is small, which is not conducive to proppant transportation during fracturing.

[0058] In order to increase the number of fracture propagations at the same time, reduce the number and time of temporary plugging operations, and increase the average fracture width at the same time, the construction displacement is now optimized. Without changing the other parameters, the construction displacement is changed from 12 m.sup.3/min to 14 m.sup.3/min and 16 m.sup.3/min respectively. The simulation calculation results of each stage are shown in FIG. 8 and FIG. 9. It can be found that when the construction flow rate is increased to 14 m.sup.3/min, the number of temporary plugging operations has not changed, and three temporary plugging operations are still required to complete the entire fracturing process, but the fracture width of the hydraulic fractures formed after each stage completed is larger than the fracture width formed by fracturing at a displacement of 12 m.sup.3/min. When the displacement increased to 16 m.sup.3/min, in addition to the obvious increase in the fracture width, after the second temporary plugging, three fracture are propagated at the same time, and the temporary plugging operation is reduced to twice. Because every time after the temporary plugging operation, it is more difficult for the fracture to propagate. To ensure that the fracture can still propagate, the bottom hole pressure will rise at this time, increasing the net pressure in the fracture, and at the same time, the fracture width will increase significantly under the action of a larger construction displacement. Therefore, by optimizing the construction displacement of dense cutting, temporary plugging and fracturing, in view of the fact that there are more perforation clusters in the seven clusters, the construction displacement must be increased to 16 m.sup.3/min and above to effectively increase the fracture width and reduce the number of temporary plugging operations at the same time to reduces the risk of operations.

[0059] The above description of the disclosed embodiments enables those skilled in the art to implement or use the disclosure. Various modifications to these embodiments will be obvious to those skilled in the art, and the general principles defined herein can be implemented in other embodiments without departing from the spirit or scope of the disclosure. Therefore, the disclosure will not be limited to the embodiments shown in this document, but should conform to the widest scope consistent with the principles and novel features disclosed in this document.