Method and device for calculating pressure propagation distance of multi-stage fractured horizontal well in shale gas reservoir

Abstract

The embodiment of the present application provides a shale gas reservoir multi-stage fracturing horizontal well different flow stage pressure propagation distance calculation method, and belongs to the field of gas reservoir development. The method comprises the following steps: obtaining shale gas reservoir basic parameters, then sequentially calculating shale gas reservoir original comprehensive compression coefficient, inter-fracture linear flow pressure propagation longest time in the reconstruction zone, inter-fracture linear flow pressure propagation distance in the reconstruction zone, inter-fracture and outside the reconstruction zone double linear flow pressure propagation longest time, inter-fracture and outside the reconstruction zone double linear flow stage reconstruction zone outside pressure propagation distance in the extension direction of the fracturing fracture, far-well zone pseudo-radial flow pressure detection radius, reconstruction zone outside horizontal well extension direction pressure propagation distance and pseudo-radial flow stage reconstruction zone outside pressure propagation distance in the extension direction of the fracturing fracture. The method can consider the change of different flow stage flow patterns, needs few parameters and is easy to obtain, and is suitable for all shale gas reservoirs with different characteristics, only needs to use the formula and the value of the related parameters to calculate, and is simple and easy to operate.

Description

Technical Field

[0001] This invention relates to the field of gas reservoir development technology, specifically to a method, apparatus, equipment, and medium for calculating the pressure propagation distance of a multi-stage fractured horizontal well in a shale gas reservoir. Background Technology

[0002] In recent years, shale gas, as one of the unconventional oil and gas resources, has become increasingly important in the energy structure, and its efficient development and utilization can further ensure energy security. Pressure propagation distance is an important interpretation parameter in oil and gas well testing and reservoir engineering calculations, often used for calculating single-well controlled reserves and production capacity equations. Because different stages of multi-stage fracturing horizontal wells in shale gas reservoirs have different flow characteristics, the pressure propagation pattern during production in fracturing horizontal wells is quite complex and cannot be calculated using conventional oil and gas reservoir detection radius formulas.

[0003] Currently, the research on the detection radius formula for vertical wells is relatively mature, while the research on pressure propagation in multi-stage fractured horizontal wells is relatively limited, and there are few reports on theoretical calculation methods for pressure propagation distance in shale gas reservoirs considering different flow stages.

[0004] It is evident that existing technologies cannot calculate the pressure propagation distance at different flow stages in multi-stage fractured horizontal wells of shale gas reservoirs. Summary of the Invention

[0005] In view of this, the purpose of this application is to provide a method, apparatus, equipment and medium for calculating the pressure propagation distance of multi-stage fractured horizontal wells in shale gas reservoirs, which can solve the problem that existing methods cannot calculate the pressure propagation distance at different flow stages in multi-stage fractured horizontal wells in shale gas reservoirs.

[0006] To solve the above-mentioned technical problems, this application is implemented as follows: In a first aspect, embodiments of this application provide a method for calculating the pressure propagation distance at different flow stages in a multi-stage fracturing horizontal well in a shale gas reservoir, including: The basic parameters of shale gas reservoirs are obtained, including permeability of the fracturing zone, permeability along the direction of fracture extension outside the fracturing zone, permeability along the direction of horizontal well extension outside the fracturing zone, original viscosity of natural gas, porosity, pore volume compressibility, water compressibility, original water saturation, horizontal well length, fracture half-length, fracture spacing, original formation pressure, and original compressibility factor. p - Z Original formation pressure on the curve p i Slope of the point tangent; Using the original formation pressure, the original compressibility factor, and the p - Z Original formation pressure on the curve pi The original comprehensive compressibility coefficient of the shale gas reservoir is calculated using the slope of the point tangent, the pore volume compressibility coefficient, the original water saturation, and the water compressibility coefficient. Using the fracture spacing, porosity, original viscosity of natural gas, permeability of the fracturing zone, and original comprehensive compressibility coefficient of the shale gas reservoir, the longest time for linear flow pressure propagation between fractures in the fracturing zone is calculated. When the production time is less than or equal to the longest time of linear flow pressure propagation between fractures in the fracturing zone, the propagation distance of linear flow pressure between fractures in the fracturing zone is calculated using the production time, the permeability of the fracturing zone, the porosity, the original viscosity of the natural gas, and the original comprehensive compressibility coefficient of the shale gas reservoir. When the production time is longer than the longest time for linear flow pressure propagation between fractures in the modified area, the longest time for bilinear flow pressure propagation between fractures and outside the modified area is calculated using the longest time for linear flow pressure propagation between fractures in the modified area, the length of the horizontal well, the half-length of the fracture, the porosity, the original viscosity of the natural gas, the original comprehensive compressibility coefficient of the shale gas reservoir, and the permeability of the fracture extension direction outside the modified area. When the production time is greater than the longest time of linear flow pressure propagation between fractures within the modified zone and less than or equal to the longest time of bilinear flow pressure propagation between fractures and outside the modified zone, the pressure propagation distance in the direction of bilinear flow outside the modified zone during the stage of bilinear flow between fractures and outside the modified zone is calculated using the fracture half-length, the permeability in the direction of the fracturing fracture extension outside the modified zone, the production time, the longest time of linear flow pressure propagation between fractures within the modified zone, the porosity, the original viscosity of natural gas, and the original comprehensive compressibility coefficient of the shale gas reservoir. When the production time is longer than the longest time for bilinear flow pressure propagation between the fracture and outside the modified zone, the pseudo-radial flow pressure detection radius in the far-well zone is calculated using the permeability of the horizontal well extension direction outside the modified zone, the permeability of the fracturing fracture extension direction outside the modified zone, the production time, the longest time for bilinear flow pressure propagation between the fracture and outside the modified zone, the porosity, the original viscosity of the natural gas, and the original comprehensive compressibility coefficient of the shale gas reservoir. When the production time is longer than the longest time of pressure propagation in the bilinear flow between the fracture and outside the modified zone, the pressure propagation distance in the direction of the horizontal well extension outside the modified zone and the pressure propagation distance in the direction of the fracturing fracture extension outside the modified zone during the quasi-radial flow stage are calculated using the length of the horizontal well, the quasi-radial flow pressure detection radius in the far well zone, the permeability in the direction of the horizontal well extension outside the modified zone and the permeability in the direction of the fracturing fracture extension outside the modified zone.

[0007] In a second aspect, embodiments of this application provide a computer device including a processor and a memory, wherein the memory stores a program or instructions, and when the program or instructions are executed by the processor, they implement the steps of the method described in the first aspect.

[0008] The method, apparatus, equipment, and medium for calculating the pressure propagation distance of multi-stage fracturing horizontal wells in shale gas reservoirs provided in the above embodiments of this application are based on sound theory, can take into account the changes in flow patterns at different flow stages, require few parameters that are easy to obtain, and are applicable to shale gas reservoirs of all characteristics. The calculation is simple and easy to operate, requiring only the use of formulas and the values ​​of relevant parameters.

[0009] Other features and advantages of the embodiments of the present invention will be described in detail in the following detailed description section. Attached Figure Description

[0010] The accompanying drawings are provided to further illustrate embodiments of the present invention and form part of the specification. They are used together with the following detailed description to explain the embodiments of the present invention, but do not constitute a limitation thereof. In the drawings: Figure 1 This document illustrates a flowchart of a method for calculating the pressure propagation distance at different flow stages in a multi-stage fracturing horizontal well in a shale gas reservoir, as provided in an embodiment of this application. Figure 2 This illustration shows a schematic diagram of the relationship between the linear flow pressure propagation distance between seams and production time in a modified area, according to an embodiment of this application. Figure 3 This illustration shows a schematic diagram of the relationship between pressure propagation distance and production time in the direction of fracturing fracture extension outside the modified zone during a bilinear flow stage between the fracture and the modified zone, according to an embodiment of this application. Figure 4 A schematic diagram illustrating the relationship between the pseudo-radial flow pressure detection radius and production time in a far-well zone, as provided in an embodiment of this application, is shown. Figure 5 This illustration shows a schematic diagram of the relationship between pressure propagation distance and production time in the extension direction of a horizontal well outside the modification zone, according to an embodiment of this application. Figure 6 This illustration shows a schematic diagram of the relationship between pressure propagation distance in the direction of fracture extension outside the pseudo-radial flow stage modification zone and production time, according to an embodiment of this application. Figure 7 The diagram shows a structural schematic of a device for calculating the pressure propagation distance at different flow stages in a multi-stage fracturing horizontal well of a shale gas reservoir, as provided in an embodiment of this application. Detailed Implementation

[0011] The technical solutions of the present invention will be clearly and completely described below with reference to the accompanying drawings in the embodiments of the present invention. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments.

[0012] The components of the embodiments of the invention described and illustrated herein can typically be arranged and designed in various different configurations. Therefore, the following detailed description of the embodiments of the invention provided in the accompanying drawings is not intended to limit the scope of the claimed invention, but merely to illustrate selected embodiments of the invention. All other embodiments obtained by those skilled in the art based on the embodiments of the invention without inventive effort are within the scope of protection of the invention.

[0013] In the following, the terms “comprising,” “having,” and their cognates, which may be used in various embodiments of the invention, are intended only to indicate a particular feature, number, step, operation, element, component, or combination thereof, and should not be construed as excluding, firstly, the presence of one or more other features, numbers, steps, operations, elements, components, or combinations thereof, or adding the possibility of one or more features, numbers, steps, operations, elements, components, or combinations thereof.

[0014] Furthermore, the terms "first," "second," and "third" are used only to distinguish descriptions and should not be interpreted as indicating or implying relative importance.

[0015] Unless otherwise specified, all terms used herein (including technical and scientific terms) shall have the same meaning as commonly understood by one of ordinary skill in the art to which the various embodiments of the invention pertain. Terms (such as those defined in commonly used dictionaries) shall be interpreted as having the same meaning as in their contextual meaning in the relevant technical field and shall not be interpreted as having an idealized or overly formal meaning, unless clearly defined in the various embodiments of the invention.

[0016] Please see Figure 1 , Figure 1 A flowchart illustrating the method for calculating pressure propagation distance at different flow stages in a multi-stage fracturing horizontal well in a shale gas reservoir, as provided in this application embodiment, is shown below. Figure 1 As shown, the method includes the following steps: Step 110: Obtain basic parameters of the shale gas reservoir, including permeability of the fracturing zone, permeability along the direction of fracture extension outside the fracturing zone, permeability along the direction of horizontal well extension outside the fracturing zone, original viscosity of natural gas, porosity, pore volume compressibility coefficient, water compressibility coefficient, original water saturation, horizontal well length, fracture half-length, fracture spacing, original formation pressure, and original compressibility factor. p - Z Original formation pressure on the curvep i Slope of the point tangent; Step 120: Utilizing the original formation pressure, the original compressibility factor, and the... p - Z Original formation pressure on the curve p i The original comprehensive compressibility coefficient of the shale gas reservoir is calculated using the slope of the point tangent, the pore volume compressibility coefficient, the original water saturation, and the water compressibility coefficient. Step 130: Calculate the longest time for linear flow pressure propagation between fractures in the fracturing zone using the fracture spacing, porosity, original viscosity of natural gas, permeability of the fracturing zone, and original comprehensive compressibility coefficient of the shale gas reservoir. Step 140: When the production time is less than or equal to the longest time of linear flow pressure propagation between fractures in the fracturing zone, calculate the linear flow pressure propagation distance between fractures in the fracturing zone using the production time, the permeability of the fracturing zone, the porosity, the original viscosity of the natural gas, and the original comprehensive compressibility coefficient of the shale gas reservoir. Step 150: If the production time is longer than the longest time for linear flow pressure propagation between fractures in the modified zone, calculate the longest time for bilinear flow pressure propagation between fractures and outside the modified zone using the longest time for linear flow pressure propagation between fractures in the modified zone, the length of the horizontal well, the half-length of the fracture, the porosity, the original viscosity of the natural gas, the original comprehensive compressibility coefficient of the shale gas reservoir, and the permeability of the fracture extension direction outside the modified zone. Step 160: When the production time is greater than the longest time of linear flow pressure propagation between fractures in the modified zone and less than or equal to the longest time of bilinear flow pressure propagation between fractures and outside the modified zone, calculate the pressure propagation distance of the bilinear flow stage between fractures and outside the modified zone using the fracture half-length, the permeability of the fracturing fracture extension direction outside the modified zone, the production time, the longest time of linear flow pressure propagation between fractures in the modified zone, the porosity, the original viscosity of natural gas, and the original comprehensive compressibility coefficient of the shale gas reservoir. Step 170: When the production time is greater than the longest propagation time of the bilinear flow pressure between the fracture and outside the modified zone, calculate the pseudo-radial flow pressure detection radius in the far well zone using the permeability of the horizontal well extension direction outside the modified zone, the permeability of the fracturing fracture extension direction outside the modified zone, the production time, the longest propagation time of the bilinear flow pressure between the fracture and outside the modified zone, the porosity, the original viscosity of the natural gas, and the original comprehensive compressibility coefficient of the shale gas reservoir. Step 180: When the production time is longer than the longest time of pressure propagation of the bilinear flow between the fracture and outside the modified zone, the pressure propagation distance in the direction of the horizontal well extension outside the modified zone and the pressure propagation distance in the direction of the fracturing fracture extension outside the modified zone are calculated using the length of the horizontal well, the quasi-radial flow pressure detection radius of the far well zone, the permeability of the horizontal well extension direction outside the modified zone and the permeability of the fracturing fracture extension direction outside the modified zone during the quasi-radial flow stage.

[0017] Specifically, in the process of shale gas extraction, the basic parameters of the shale gas reservoir should be obtained in advance. Please refer to Table 1, which shows the values ​​and units of the basic parameters of the shale gas reservoir.

[0018] Table 1 Basic parameters of shale gas reservoirs

[0019] Based on the basic parameters of shale gas reservoirs, the method provided in this application utilizes computer equipment to first calculate the original comprehensive compressibility coefficient of the shale gas reservoir and the longest propagation time of inter-fracture linear flow pressure within the stirred zone. Production time refers to the cumulative number of days elapsed since the well was commissioned. It is understood that the parameters calculated for different production times may differ. Specifically, when the production time is less than or equal to the longest time of linear flow pressure propagation between fractures within the modified zone, the pressure propagation distance of linear flow between fractures within the modified zone is calculated; when the production time is greater than the longest time of linear flow pressure propagation between fractures within the modified zone, the longest time of pressure propagation between fractures and the bilinear flow outside the modified zone is calculated; when the production time is greater than the longest time of linear flow pressure propagation between fractures within the modified zone and less than or equal to the longest time of pressure propagation between fractures and the bilinear flow outside the modified zone, the pressure propagation distance in the direction of fracture extension outside the modified zone during the bilinear flow stage is calculated; when the production time is greater than the longest time of pressure propagation between fractures and the bilinear flow outside the modified zone, the pseudo-radial flow pressure detection radius in the far-well zone is calculated, and based on the pseudo-radial flow pressure detection radius in the far-well zone, the pressure propagation distance in the direction of horizontal well extension outside the modified zone and the pressure propagation distance in the direction of fracture extension outside the modified zone during the pseudo-radial flow stage are calculated, thereby realizing the calculation of pressure propagation distances in different flow stages of multi-stage fractured horizontal wells in shale gas reservoirs.

[0020] The method for calculating the pressure propagation distance of multi-stage fractured horizontal wells in shale gas reservoirs provided in this application is based on sound theory, can take into account the changes in flow patterns at different flow stages, requires few parameters that are easy to obtain, and is applicable to shale gas reservoirs of all characteristics. It is simple and easy to operate, requiring only the use of formulas and the values ​​of relevant parameters, thus providing theoretical support for the exploitation of shale gas reservoirs.

[0021] In one optional implementation, step 120 includes: The original comprehensive compressibility coefficient of shale gas reservoirs is calculated using a first preset formula, wherein the first preset formula includes:

[0022] In the formula, C ti This represents the original comprehensive compressibility coefficient of the shale gas reservoir. C p Indicates the pore volume compressibility coefficient, p i Indicates the original formation pressure. Z i Indicates the original compression factor. express p - Z Original formation pressure on the curve p i Slope of the tangent line at the point, S wi Indicates the initial water saturation. C w This represents the compressibility coefficient of water.

[0023] Specifically, by substituting the values ​​of the basic parameters in Table 1 into the first preset formula, the original comprehensive compressibility coefficient of the shale gas reservoir can be calculated. C ti =0.0376 MPa -1 .

[0024] In one optional implementation, step 130 includes: The longest propagation time of linear flow pressure between joints in the modified area is calculated using a second preset formula, wherein the second preset formula includes:

[0025] In the formula, t 0 indicates the longest propagation time of linear flow pressure between joints within the modified area. d Indicates the crack spacing. Indicates porosity. μ i Indicates the original viscosity of natural gas. C ti This represents the original comprehensive compressibility coefficient of the shale gas reservoir. k srv This indicates the permeability of the fracturing zone.

[0026] Specifically, the basic parameters in Table 1 and the original comprehensive compressibility coefficient of the shale gas reservoir will be used as a reference. C ti Substituting the value of into the second preset formula, the longest time for linear flow pressure propagation between joints in the modified area can be calculated. t 0 = 32.78 d.

[0027] In one optional implementation, step 140 includes: When the production time is less than or equal to the longest time of linear flow pressure propagation between seams in the modified area, the propagation distance of linear flow pressure between seams in the modified area is calculated using a third preset formula, wherein the third preset formula includes:

[0028] In the formula, x srv This indicates the propagation distance of linear flow pressure between joints within the modified area. k srv Indicates the permeability of the fracturing zone. t Indicates production time. Indicates porosity. μ i Indicates the original viscosity of natural gas. C ti This represents the original comprehensive compressibility coefficient of a shale gas reservoir.

[0029] Specifically, with t For example, =20 d, t <t 0, the basic parameters in Table 1, the original comprehensive compressibility coefficient of the shale gas reservoir C ti and production time t Substituting the value of into the third preset formula, the propagation distance of the linear flow pressure between the seams in the modified area can be calculated. x srv =39.04 m.

[0030] Understandably, during production time t The longest time for linear flow pressure propagation between joints within the modified area is greater than the maximum time. t Under the condition of 0, the propagation distance of linear flow pressure between joints in the modified area x srv = d / 2=50 m.

[0031] In one optional implementation, step 150 includes: If the production time exceeds the maximum time for linear flow pressure propagation between seams within the modified area, the maximum time for bilinear flow pressure propagation between seams and outside the modified area is calculated using a fourth preset formula. The fourth preset formula includes:

[0032] In the formula, t 1 indicates the longest propagation time of bilinear flow pressure between the seam and outside the modified area. t 0 indicates the longest propagation time of linear flow pressure between joints within the modified area.L H Indicates the length of the horizontal well. L f Indicates half the length of the crack. Indicates porosity. μ i Indicates the original viscosity of natural gas. C ti This represents the original comprehensive compressibility coefficient of the shale gas reservoir. k y This indicates the permeability along the direction of the fracturing fractures outside the modified area.

[0033] Specifically, the basic parameters in Table 1 and the original comprehensive compressibility coefficient of the shale gas reservoir will be used as references. C ti And the longest time of linear flow pressure propagation between seams in the modified area. t Substituting the value of 0 into the fourth preset formula, the longest time for bilinear flow pressure propagation between the seam and outside the modified area can be calculated. t 1 = 13146.73 d.

[0034] In one optional implementation, step 160 includes: When the production time is greater than the longest time for linear flow pressure propagation between fractures within the modified zone, and less than or equal to the longest time for bilinear flow pressure propagation between fractures and outside the modified zone, the pressure propagation distance in the direction of fracture extension outside the modified zone during the bilinear flow stage between fractures and outside the modified zone is calculated using a fifth preset formula. The fifth preset formula includes:

[0035] In the formula, y dl This indicates the pressure propagation distance along the direction of the fracturing fracture extension outside the modified zone during the bilinear flow stage between the fracture and the modified zone. L f Indicates half the length of the crack. k y This indicates the permeability along the direction of the hydraulic fracturing fractures outside the modified area. t Indicates production time. t 0 indicates the longest propagation time of linear flow pressure between joints within the modified area. Indicates porosity. μ i Indicates the original viscosity of natural gas. C ti This represents the original comprehensive compressibility coefficient of a shale gas reservoir.

[0036] Specifically, with t For example, =10000 d, t 0< t < t1. The basic parameters and the original comprehensive compressibility coefficient of the shale gas reservoir are included. C ti Production time t And the longest time of linear flow pressure propagation between seams in the modified area. t Substituting the value of 0 into the fifth preset formula, the pressure propagation distance in the direction of the fracturing fracture extension in the bilinear flow stage outside the modified zone can be calculated. y dl =448.63 m.

[0037] In one optional implementation, step 170 includes: When the production time exceeds the longest propagation time of the bilinear flow pressure between the fracture and outside the modified zone, the sixth preset formula is used to calculate the pseudo-radial flow pressure detection radius in the far-well zone. The sixth preset formula includes:

[0038] In the formula, r Indicates the radial flow pressure detection radius in the far-well zone. k x This indicates the permeability along the direction of the horizontal well extension outside the renovation area. k y This indicates the permeability along the direction of the hydraulic fracturing fractures outside the modified area. t Indicates production time. t 1 indicates the longest propagation time of bilinear flow pressure between the seam and outside the modified area. Indicates porosity. μ i Indicates the original viscosity of natural gas. C ti This represents the original comprehensive compressibility coefficient of a shale gas reservoir.

[0039] Specifically, with t For example, =16000 d, t > t 1. The basic parameters and the original comprehensive compressibility coefficient of the shale gas reservoir are included. C ti Production time t and the longest duration of bilinear flow pressure propagation between the seam and outside the modified area. t Substituting the value of 1 into the sixth preset formula, the pseudo-radial flow pressure detection radius in the far-well zone can be calculated. r =128.53 m.

[0040] In one optional implementation, step 180 includes: When the production time exceeds the longest possible pressure propagation time of the bilinear flow between the fracture and outside the modified zone, the pressure propagation distance in the direction of horizontal well extension outside the modified zone is calculated using a seventh preset formula, wherein the seventh preset formula includes:

[0041] In the formula, x This indicates the pressure propagation distance in the direction of the horizontal well extension outside the renovation area. L H Indicates the length of the horizontal well. r Indicates the radial flow pressure detection radius in the far-well zone. k x This indicates the permeability along the direction of the horizontal well extension outside the renovation area. k y This indicates the permeability along the direction of the hydraulic fracturing fractures outside the modified area; The pressure propagation distance along the direction of the fracturing fractures outside the modified zone in the pseudo-radial flow stage is calculated using the eighth preset formula, wherein the eighth preset formula includes:

[0042] In the formula, y pr This indicates the pressure propagation distance along the direction of the fracturing fractures outside the modified zone during the quasi-radial flow stage. L H Indicates the length of the horizontal well. r Indicates the radial flow pressure detection radius in the far-well zone. k x This indicates the permeability along the direction of the horizontal well extension outside the renovation area. k y This indicates the permeability along the direction of the fracturing fractures outside the modified area.

[0043] Specifically, with t For example, =16000 d, t > t 1. Combine basic parameters and the original comprehensive compressibility coefficient of shale gas reservoirs. C ti Substituting the value of into the seventh preset formula, the pressure propagation distance in the direction of the horizontal well extension outside the modification zone can be calculated. x =608.08 m. Simultaneously, the basic parameters and the original comprehensive compressibility coefficient of the shale gas reservoir were also considered. C ti Substituting the value of into the eighth preset formula, the pressure propagation distance in the direction of the external fracturing fracture extension in the pseudo-radial flow stage modification zone can be calculated. y pr =652.85m.

[0044] In one optional implementation, the method further includes: Coordinate graphs were plotted based on the linear flow pressure propagation distance between fractures within the modified zone, the pressure propagation distance between fractures and the direction of fracturing fracture extension outside the modified zone during the bilinear flow stage, the quasi-radial flow pressure detection radius in the far-well zone, the pressure propagation distance in the direction of horizontal well extension outside the modified zone, the pressure propagation distance in the direction of fracturing fracture extension outside the modified zone during the quasi-radial flow stage, and the production time.

[0045] Specifically, all calculation results are summarized in Table 2.

[0046] Table 2 Pressure propagation distance in different directions at different production times

[0047] Using the data in Table 2, based on production time t The horizontal axis represents the distance of linear flow pressure propagation between joints within the modified area. x srv Pressure propagation distance in the direction of fracture extension outside the fracturing zone during the bilinear flow stage between fractures and outside the fracturing zone. y dl Radial flow pressure detection radius in the far-well zone r Pressure propagation distance in the direction of horizontal well extension outside the renovation area x And the pressure propagation distance in the direction of the fracturing fracture extension outside the pseudo-radial flow stage modification zone. y pr Plot a coordinate graph with the vertical axis as the ordinate, and you will get the following: Figure 2-6 The diagram shown illustrates the relationship between the calculated parameters and production time. The coordinate graph provides a more intuitive understanding of this relationship.

[0048] For a method embodiment corresponding to the above, please refer to [link / reference]. Figure 7 , Figure 7 This is a schematic diagram of the pressure propagation distance calculation device for different flow stages in a multi-stage fracturing horizontal well of a shale gas reservoir provided in an embodiment of this application, as shown below. Figure 7 As shown, the pressure propagation distance calculation device 1000 for different flow stages in a multi-stage fractured horizontal well of a shale gas reservoir includes: The acquisition module 1001 is used to acquire basic parameters of shale gas reservoirs, including permeability of the fracturing zone, permeability along the direction of fracture extension outside the fracturing zone, permeability along the direction of horizontal well extension outside the fracturing zone, original viscosity of natural gas, porosity, pore volume compressibility coefficient, water compressibility coefficient, original water saturation, horizontal well length, fracture half-length, fracture spacing, original formation pressure, and original compressibility factor. p - Z Original formation pressure on the curvep i Slope of the point tangent; Shale gas reservoir original comprehensive compressibility coefficient calculation module 1002, used to calculate the original formation pressure, the original compressibility factor, and the... p - Z Original formation pressure on the curve p i The original comprehensive compressibility coefficient of the shale gas reservoir is calculated using the slope of the point tangent, the pore volume compressibility coefficient, the original water saturation, and the water compressibility coefficient. The module 1003 for calculating the longest propagation time of linear flow pressure between fractures in the fracturing zone is used to calculate the longest propagation time of linear flow pressure between fractures in the fracturing zone using the fracture spacing, porosity, original viscosity of natural gas, permeability of the fracturing zone, and original comprehensive compressibility coefficient of the shale gas reservoir. The module 1004 for calculating the propagation distance of linear flow pressure between fractures in the fracturing zone is used to calculate the propagation distance of linear flow pressure between fractures in the fracturing zone when the production time is less than or equal to the longest time of linear flow pressure propagation between fractures in the fracturing zone, using the production time, the permeability of the fracturing zone, the porosity, the original viscosity of the natural gas, and the original comprehensive compressibility coefficient of the shale gas reservoir. The module 1005 for calculating the longest time of bilinear flow pressure propagation between fractures and outside the modified zone is used to calculate the longest time of bilinear flow pressure propagation between fractures and outside the modified zone when the production time is longer than the longest time of pressure propagation between fractures and outside the modified zone. This calculation is based on the longest time of pressure propagation between fractures and outside the modified zone, the length of the horizontal well, the half-length of the fracture, the porosity, the original viscosity of the natural gas, the original comprehensive compressibility coefficient of the shale gas reservoir, and the permeability in the direction of the fracture extension outside the modified zone. The pressure propagation distance calculation module 1006 for the bilinear flow stage between fractures and outside the modified zone is used to calculate the pressure propagation distance in the direction of the fracturing fracture extension during the bilinear flow stage between fractures and outside the modified zone, when the production time is greater than the longest pressure propagation time of the linear flow between fractures within the modified zone and less than or equal to the longest pressure propagation time of the bilinear flow between fractures and outside the modified zone, using the fracture half-length, the permeability in the direction of the fracturing fracture extension outside the modified zone, the production time, the longest pressure propagation time of the linear flow between fractures within the modified zone, the porosity, the original viscosity of natural gas, and the original comprehensive compressibility coefficient of the shale gas reservoir. The pseudo-radial flow pressure detection radius calculation module 1007 in the far-well zone is used to calculate the pseudo-radial flow pressure detection radius in the far-well zone when the production time is greater than the longest time of bilinear flow pressure propagation between the fracture and outside the reformed area, using the permeability of the horizontal well extension direction outside the reformed area, the permeability of the fracturing fracture extension direction outside the reformed area, the production time, the longest time of bilinear flow pressure propagation between the fracture and outside the reformed area, the porosity, the original viscosity of natural gas, and the original comprehensive compressibility coefficient of the shale gas reservoir. The module 1008, which calculates the pressure propagation distance in the direction of the horizontal well extension outside the modified zone and the pressure propagation distance in the direction of the fracturing fracture extension outside the modified zone during the pseudo-radial flow stage, is used to calculate the pressure propagation distance in the direction of the horizontal well extension outside the modified zone and the pressure propagation distance in the direction of the fracturing fracture extension during the pseudo-radial flow stage when the production time is greater than the longest time of pressure propagation between the fracture and the modified zone. It uses the length of the horizontal well, the pseudo-radial flow pressure detection radius of the far well zone, the permeability in the direction of the horizontal well extension outside the modified zone, and the permeability in the direction of the fracturing fracture extension outside the modified zone.

[0049] The pressure propagation distance calculation device for multi-stage fracturing horizontal wells in shale gas reservoirs provided in this application embodiment can achieve... Figure 1 The method embodiments described herein are for calculating the pressure propagation distance of multi-stage fractured horizontal wells in shale gas reservoirs at different flow stages, and can achieve the same technical effect. To avoid repetition, they will not be described again here.

[0050] Optionally, this application embodiment also provides a computer device, including a processor and a memory, wherein the memory stores a program or instructions. When the program or instructions are executed by the processor, they implement the various processes of the above-described embodiment of the method for calculating the pressure propagation distance at different flow stages in a multi-stage fracturing horizontal well of a shale gas reservoir, and can achieve the same technical effect. To avoid repetition, they will not be described again here.

[0051] Optionally, this application embodiment also provides a computer-readable storage medium storing a program or instructions. When the program or instructions are executed by a processor, they implement the various processes of the above-described embodiment of the method for calculating the pressure propagation distance at different flow stages in a multi-stage fracturing horizontal well of a shale gas reservoir, and can achieve the same technical effect. To avoid repetition, they will not be described again here.

[0052] The processor is the processor in the computer device described in the above embodiments. The readable storage medium includes computer-readable storage media, such as computer read-only memory (ROM), random access memory (RAM), magnetic disk, or optical disk.

[0053] Those skilled in the art will understand that embodiments of this application can be provided as methods, systems, or computer program products. Therefore, this application can take the form of a completely hardware embodiment, a completely software embodiment, or an embodiment combining software and hardware aspects. Furthermore, this application can take the form of a computer program product embodied on one or more computer-usable storage media (including, but not limited to, disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0054] This application is described with reference to flowchart illustrations and / or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of this application. It will be understood that each block of the flowchart illustrations and / or block diagrams, and combinations of blocks in the flowchart illustrations and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, special-purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, generate instructions for implementing the flowchart... Figure 1 One or more processes and / or boxes Figure 1 A device that provides the functions specified in one or more boxes.

[0055] These computer program instructions may also be stored in a computer-readable storage medium that can direct a computer or other programmable data processing device to function in a particular manner, such that the instructions stored in the computer-readable storage medium produce an article of manufacture including instruction means, which are implemented in a process Figure 1 One or more processes and / or boxes Figure 1 The function specified in one or more boxes.

[0056] These computer program instructions may also be loaded onto a computer or other programmable data processing equipment to cause a series of operational steps to be performed on the computer or other programmable equipment to produce a computer-implemented process, thereby providing instructions that execute on the computer or other programmable equipment for implementing the process. Figure 1 One or more processes and / or boxes Figure 1 The steps of the function specified in one or more boxes.

[0057] In a typical configuration, a computing device includes one or more processors (CPU), input / output interfaces, network interfaces, and memory.

[0058] Memory may include non-persistent memory in computer-readable media, such as random access memory (RAM) and / or non-volatile memory, such as read-only memory (ROM) or flash RAM. Memory is an example of computer-readable media.

[0059] Computer-readable media includes both permanent and non-permanent, removable and non-removable media that can store information using any method or technology. Information can be computer-readable instructions, data structures, modules of programs, or other data. Examples of computer storage media include, but are not limited to, phase-change memory (PRAM), static random access memory (SRAM), dynamic random access memory (DRAM), other types of random access memory (RAM), read-only memory (ROM), electrically erasable programmable read-only memory (EEPROM), flash memory or other memory technologies, CD-ROM, digital versatile optical disc (DVD) or other optical storage, magnetic tape, magnetic magnetic disk storage or other magnetic storage devices, or any other non-transferable medium that can be used to store information accessible by a computing device. As defined herein, computer-readable media does not include transient computer-readable media, such as modulated data signals and carrier waves.

[0060] It should also be noted that the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such process, method, article, or apparatus. Unless otherwise specified, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes that element.

[0061] The above are merely embodiments of this application and are not intended to limit the scope of this application. Various modifications and variations can be made to this application by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of this application should be included within the scope of the claims of this application.

Claims

1. A method for calculating the pressure propagation distance at different flow stages in a multi-stage fractured horizontal well of a shale gas reservoir, characterized in that... include: The basic parameters of shale gas reservoirs are obtained, including permeability of the fracturing zone, permeability along the direction of fracture extension outside the fracturing zone, permeability along the direction of horizontal well extension outside the fracturing zone, original viscosity of natural gas, porosity, pore volume compressibility, water compressibility, original water saturation, horizontal well length, fracture half-length, fracture spacing, original formation pressure, and original compressibility factor. p - Z Original formation pressure on the curve p i Slope of the point tangent; Using the original formation pressure, the original compressibility factor, and the p - Z Original formation pressure on the curve p i The original comprehensive compressibility coefficient of the shale gas reservoir is calculated using the slope of the point tangent, the pore volume compressibility coefficient, the original water saturation, and the water compressibility coefficient. The longest propagation time of linear flow pressure between joints in the modified area is calculated using a second preset formula, wherein the second preset formula includes: In the formula, t 0 indicates the longest propagation time of linear flow pressure between joints within the modified area. d Indicates crack spacing, Indicates porosity. μ i Indicates the original viscosity of natural gas. C ti This represents the original comprehensive compressibility coefficient of the shale gas reservoir. k srv This represents the permeability of the fracturing zone, where, during production time... t The longest time for linear flow pressure propagation between joints within the modified area is greater than the maximum time. t Under the condition of 0, the propagation distance of linear flow pressure between joints in the modified area x srv = d / 2; When the production time is less than or equal to the longest time of linear flow pressure propagation between fractures in the fracturing zone, the propagation distance of linear flow pressure between fractures in the fracturing zone is calculated using the production time, the permeability of the fracturing zone, the porosity, the original viscosity of the natural gas, and the original comprehensive compressibility coefficient of the shale gas reservoir. If the production time exceeds the maximum time for linear flow pressure propagation between seams within the modified area, the maximum time for bilinear flow pressure propagation between seams and outside the modified area is calculated using a fourth preset formula. The fourth preset formula includes: In the formula, t 1 indicates the longest propagation time of bilinear flow pressure between the seam and outside the modified area. t 0 indicates the longest propagation time of linear flow pressure between joints within the modified area. L H Indicates the length of the horizontal well. L f Indicates half the length of the crack. Indicates porosity. μ i Indicates the original viscosity of natural gas. C ti This represents the original comprehensive compressibility coefficient of the shale gas reservoir. k y This indicates the permeability along the direction of the hydraulic fracturing fractures outside the modified area; When the production time is greater than the longest time of linear flow pressure propagation between fractures within the modified zone and less than or equal to the longest time of bilinear flow pressure propagation between fractures and outside the modified zone, the pressure propagation distance in the direction of bilinear flow outside the modified zone during the stage of bilinear flow between fractures and outside the modified zone is calculated using the fracture half-length, the permeability in the direction of the fracturing fracture extension outside the modified zone, the production time, the longest time of linear flow pressure propagation between fractures within the modified zone, the porosity, the original viscosity of natural gas, and the original comprehensive compressibility coefficient of the shale gas reservoir. When the production time is longer than the longest time for bilinear flow pressure propagation between the fracture and outside the modified zone, the pseudo-radial flow pressure detection radius in the far-well zone is calculated using the permeability of the horizontal well extension direction outside the modified zone, the permeability of the fracturing fracture extension direction outside the modified zone, the production time, the longest time for bilinear flow pressure propagation between the fracture and outside the modified zone, the porosity, the original viscosity of the natural gas, and the original comprehensive compressibility coefficient of the shale gas reservoir. When the production time is longer than the longest time of pressure propagation in the bilinear flow between the fracture and outside the modified zone, the pressure propagation distance in the direction of the horizontal well extension outside the modified zone and the pressure propagation distance in the direction of the fracturing fracture extension outside the modified zone during the quasi-radial flow stage are calculated using the length of the horizontal well, the quasi-radial flow pressure detection radius in the far well zone, the permeability in the direction of the horizontal well extension outside the modified zone and the permeability in the direction of the fracturing fracture extension outside the modified zone.

2. The method according to claim 1, characterized in that, The method utilizes the original formation pressure, the original compressibility factor, and the... p - Z Original formation pressure on the curve p i The original comprehensive compressibility coefficient of the shale gas reservoir is calculated using the point tangent slope, the pore volume compressibility coefficient, the original water saturation, and the water compressibility coefficient, including: The original comprehensive compressibility coefficient of shale gas reservoirs is calculated using a first preset formula, wherein the first preset formula includes: In the formula, C ti This represents the original comprehensive compressibility coefficient of the shale gas reservoir. C p Indicates the pore volume compressibility coefficient, p i Indicates the original formation pressure. Z i Indicates the original compression factor. express p - Z Original formation pressure on the curve p i Slope of the tangent line at the point, S wi Indicates the initial water saturation. C w This represents the compressibility coefficient of water.

3. The method according to claim 1, characterized in that, The calculation of the inter-seam linear flow pressure propagation distance within the modified area, when the production time is less than or equal to the longest time of inter-seam linear flow pressure propagation within the modified area, includes: When the production time is less than or equal to the longest time of linear flow pressure propagation between seams in the modified area, the propagation distance of linear flow pressure between seams in the modified area is calculated using a third preset formula, wherein the third preset formula includes: In the formula, x srv This indicates the propagation distance of linear flow pressure between joints within the modified area. k srv Indicates the permeability of the fracturing zone. t Indicates production time. Indicates porosity. μ i Indicates the original viscosity of natural gas. C ti This represents the original comprehensive compressibility coefficient of a shale gas reservoir.

4. The method according to claim 1, characterized in that, The calculation of the pressure propagation distance in the direction of the fracturing fracture extension outside the modified zone during the bilinear flow stage, when the production time is greater than the longest time of linear flow pressure propagation between the fractures within the modified zone and less than or equal to the longest time of bilinear flow pressure propagation between the fractures and outside the modified zone, includes: When the production time is greater than the longest time for linear flow pressure propagation between fractures within the modified zone, and less than or equal to the longest time for bilinear flow pressure propagation between fractures and outside the modified zone, the pressure propagation distance in the direction of fracture extension outside the modified zone during the bilinear flow stage between fractures and outside the modified zone is calculated using a fifth preset formula. The fifth preset formula includes: In the formula, y dl This indicates the pressure propagation distance along the direction of the fracturing fracture extension outside the modified zone during the bilinear flow stage between the fracture and the modified zone. L f Indicates half the length of the crack. k y This indicates the permeability along the direction of the hydraulic fracturing fractures outside the modified area. t Indicates production time. t 0 indicates the longest propagation time of linear flow pressure between joints within the modified area. Indicates porosity. μ i Indicates the original viscosity of natural gas. C ti This represents the original comprehensive compressibility coefficient of a shale gas reservoir.

5. The method according to claim 1, characterized in that, When the production time is longer than the longest propagation time of the bilinear flow pressure between the fracture and outside the modified zone, the calculation of the pseudo-radial flow pressure detection radius in the far-well zone includes: When the production time exceeds the longest propagation time of the bilinear flow pressure between the fracture and outside the modified zone, the sixth preset formula is used to calculate the pseudo-radial flow pressure detection radius in the far-well zone. The sixth preset formula includes: In the formula, r Indicates the radial flow pressure detection radius in the far-well zone. k x This indicates the permeability along the direction of the horizontal well extension outside the renovation area. k y This indicates the permeability along the direction of the hydraulic fracturing fractures outside the modified area. t Indicates production time. t 1 indicates the longest propagation time of bilinear flow pressure between the seam and outside the modified area. Indicates porosity. μ i Indicates the original viscosity of natural gas. C ti This represents the original comprehensive compressibility coefficient of a shale gas reservoir.

6. The method according to claim 1, characterized in that, When the production time is greater than the longest time for bilinear flow pressure propagation between the fracture and outside the modified zone, the calculation of the pressure propagation distance in the direction of horizontal well extension outside the modified zone and the pressure propagation distance in the direction of fracturing fracture extension outside the modified zone during the pseudo-radial flow stage includes: When the production time exceeds the longest possible pressure propagation time of the bilinear flow between the fracture and outside the modified zone, the pressure propagation distance in the direction of horizontal well extension outside the modified zone is calculated using a seventh preset formula, wherein the seventh preset formula includes: In the formula, x This indicates the pressure propagation distance in the direction of the horizontal well extension outside the renovation area. L H Indicates the length of the horizontal well. r Indicates the radial flow pressure detection radius in the far-well zone. k x This indicates the permeability along the direction of the horizontal well extension outside the renovation area. k y This indicates the permeability along the direction of the hydraulic fracturing fractures outside the modified area; The pressure propagation distance along the direction of the fracturing fracture extension outside the modified zone in the pseudo-radial flow stage is calculated using the eighth preset formula, wherein the eighth preset formula includes: In the formula, y pr This indicates the pressure propagation distance along the direction of the fracturing fractures outside the modified zone during the quasi-radial flow stage. L H Indicates the length of the horizontal well. r Indicates the radial flow pressure detection radius in the far-well zone. k x This indicates the permeability along the direction of the horizontal well extension outside the renovation area. k y This indicates the permeability along the direction of the fracturing fractures outside the modified area.

7. The method according to claim 1, characterized in that, Also includes: Coordinate graphs were plotted based on the linear flow pressure propagation distance between fractures within the modified zone, the pressure propagation distance between fractures and the direction of fracturing fracture extension outside the modified zone during the bilinear flow stage, the quasi-radial flow pressure detection radius in the far-well zone, the pressure propagation distance in the direction of horizontal well extension outside the modified zone, the pressure propagation distance in the direction of fracturing fracture extension outside the modified zone during the quasi-radial flow stage, and the production time.

8. A computer device, characterized in that, It includes a processor and a memory, wherein the memory stores a program or instructions, and when the program or instructions are executed by the processor, they implement the steps of the method for calculating the pressure propagation distance at different flow stages in a multi-stage fracturing horizontal well of a shale gas reservoir as described in any one of claims 1-7.

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