Method and device for determining fracturing density of horizontal wells in tight sandstone gas reservoirs

Abstract

The present application discloses a method and device for determining the density of fracture distribution in horizontal wells of tight sandstone gas reservoirs, wherein the determination method comprises: obtaining the geostress data, basic rock mechanics parameters and core permeability of the rock formation where the target fracture section is located; calculating the first fracture spacing of the target fracture section according to the geostress data and the basic rock mechanics parameters; calculating the second fracture spacing of the target fracture section according to the core permeability; determining the fracture density of the target fracture section based on the length of the target fracture section, the first fracture spacing and the second fracture spacing. The method and device for determining the density of fracture distribution in horizontal wells of tight sandstone gas reservoirs disclosed in the present application can improve the universality of the high-density multi-fracture fracturing process of horizontal wells.

Description

Technical Field

[0001] The present application relates to the field of gas reservoir exploration technology, and in particular to a method and device for determining the density of fracturing distribution of horizontal wells in tight sandstone gas reservoirs. Background Art

[0002] Tight sandstone gas reservoirs account for a considerable proportion of my country's natural gas reserves, with prospective resources exceeding 10 trillion cubic meters, accounting for 1 / 5 of the country's total natural gas resources. However, without reservoir transformation, tight sandstone gas reservoirs are generally difficult to achieve production with industrial development value. Therefore, reservoir transformation technology for tight sandstone gas reservoirs has made great progress in recent years.

[0003] Since the natural fractures of sandstone gas reservoirs are often limited or even undeveloped, and there are no high-density natural fractures, bedding, foliation and other weak structural surfaces, sandstone hydraulic fracturing mainly forms long straight double-wing fractures. Among the many horizontal well fracturing technologies for tight sandstone reservoirs, the effects of "high-density completion fracturing" and "dense cutting fracturing" are the most prominent. Among them, high-density completion fracturing usually adopts the method of arranging multiple perforation clusters in a certain fracturing section, and then forming multiple hydraulic fractures in the section by pumping high-pressure liquid into the perforation clusters; dense cutting fracturing usually sets each fracturing section with only one cluster of holes, so that only one hydraulic fracture is formed. The difference between it and high-density completion fracturing is that the fracturing section is shorter, so the whole horizontal section can be divided into more sections. In short, the starting point of the above two fracturing technologies is to increase the density of fractures, make full use of the length of the horizontal section, and achieve the purpose of fully transforming the reservoir. They are very promising technologies.

[0004] However, it should be noted that if the distance between adjacent perforation clusters is too close, the density of hydraulic fractures will increase, which will inevitably cause more significant inter-fracture interference effects, mainly manifested in the first-formed fractures squeezing subsequent fractures in the fracture width direction, increasing the difficulty of expanding subsequent fractures, thereby causing uneven growth of hydraulic fractures along the fracture length direction, making it difficult to fully transform some well sections with suppressed fracture lengths. At present, the design of hydraulic fracture locations for the above two high-density fracture fracturing technologies is mostly carried out by field tests and empirical methods through effect summaries, lacking theoretical guidance, so it has poor universality and is not applicable to other blocks where reservoir mechanical properties have changed. Summary of the invention

[0005] In view of this, the present application provides a method and device for determining the density of fracture distribution in horizontal wells of tight sandstone gas reservoirs, so as to improve the universality of the high-density multi-fracture fracturing process of horizontal wells.

[0006] This application specifically adopts the following technical solutions:

[0007] One aspect of the present application is to provide a method for determining the density of fracture distribution in a horizontal well of a tight sandstone gas reservoir, characterized in that the method comprises:

[0008] Obtain the in-situ stress data, basic rock mechanics parameters and core permeability of the rock formation where the target fracturing well section is located;

[0009] Calculating the first fracture spacing of the target fracturing well section according to the geostress data and the basic rock mechanics parameters;

[0010] Calculating the second fracture spacing of the target fracturing well section according to the core permeability;

[0011] The slit density of the target fracturing well section is determined based on the length of the target fracturing well section, the first slit spacing, and the second slit spacing.

[0012] Optionally, determining the seam density of the target fracturing well section based on the length of the target fracturing well section, the first seam spacing, and the second seam spacing includes:

[0013] Obtaining the length of the target fracturing well section;

[0014] The first seam spacing and the second seam spacing are compared, wherein when the first seam spacing is greater than the second seam spacing, the seam density is calculated by the following formula:

[0015] s=L / J min

[0016] When the first seam spacing is smaller than the second seam spacing, the seam density is calculated by the following formula:

[0017] s=L / D max

[0018] Where s is the density of the fractures; L is the length of the target fracturing section, m; J min is the first seam spacing, m; D max is the second slit spacing, m.

[0019] Optionally, the obtaining of ground stress data and basic rock mechanics parameters of the rock formation where the target fracturing well section is located includes:

[0020] Acquiring logging data of the target fracturing well section and interpreting the logging data;

[0021] Based on the interpretation data of the logging data, the geostress data and basic rock mechanics parameters of the target fracturing section are obtained, wherein the geostress data include the minimum horizontal principal stress, and the basic rock mechanics parameters include elastic modulus, Poisson's ratio and tensile strength.

[0022] Optionally, the obtaining of geostress data of the target fracturing well section based on the well logging data interpretation data includes:

[0023] Based on the well logging data interpretation data, draw a geostress profile and a fracture pressure profile;

[0024] The minimum horizontal principal stress is determined from the in-situ stress profile and the fracture pressure profile.

[0025] Optionally, the calculating the first fracture spacing of the target fracturing well section based on the geostress data and the rock mechanics basic parameters includes:

[0026] The induced stress field is constructed, and the induced stress at any point (x1, z) in the induced stress field is calculated by the stress-strain constitutive equation:

[0027]

[0028]

[0029] Where:

[0030]

[0031]

[0032] Among them, Δσ x is the horizontal induced stress, Pa; Δσ z is the vertical induced stress, Pa; p is the flow pressure in the wellbore, Pa; c is the half fracture height, m;

[0033] Based on the horizontal induced stress and the geostress data, the horizontal induced superimposed stress at any point (x1, z) in the stress field is calculated:

[0034]

[0035] Among them, σ X is the horizontal induced superimposed stress, Pa; σ min is the minimum horizontal principal stress, Pa;

[0036] When the horizontal induced superposition stress meets a preset condition, the first seam spacing is determined.

[0037] Optionally, when the horizontal induced superposition stress satisfies a preset condition, determining the first slit spacing includes:

[0038] When the horizontal induced superimposed stress satisfies σ X =3S T +σ min , calculate the value of x1 in (x1, 0) corresponding to the horizontal induced stress;

[0039] The first gap spacing is determined according to the following formula:

[0040] J min =x1

[0041] Among them, S T is the tensile strength, Pa; J min is the first seam spacing, m.

[0042] Optionally, obtaining the core permeability of the rock formation where the target fracturing well section is located includes:

[0043] Acquire a full-diameter core in the target fracturing well section;

[0044] Based on the full-diameter core acquisition portion standard core plug, the core permeability of the standard core plug is measured.

[0045] Optionally, the calculating the second fracture spacing of the target fracturing well section based on the core permeability includes:

[0046] Construct an effective seepage pressure field and determine any point (x2, y) in the effective seepage pressure field:

[0047]

[0048] Wherein, (ζ, ω) is the coordinate of (x2, y) in the elliptical coordinate system corresponding to the effective seepage pressure field; a and b are the major axis and minor axis of the ellipse corresponding to (ζ, ω), respectively, and the direction of the minor axis is parallel to the gas seepage direction; c is the half-crack height, m;

[0049] Determine the isobar morphology distribution function in the effective seepage pressure field:

[0050]

[0051] In the formula,

[0052]

[0053] Where p is the fluid flow pressure at the fracture, Pa; p wf is the bottom hole pressure, Pa; μ is the fluid viscosity, Pa·s; Z is the compressibility factor of the fluid under reservoir conditions; T is the reservoir temperature, K; k is the permeability, D; q s is the wellhead fluid flow rate, m 3 / s;p s is the wellhead pressure, MPa; H is the fracture height, m; T s is the wellhead temperature, K; Z s is the gas compressibility factor;

[0054] The second slit spacing is determined according to the distribution of isobars in the effective seepage pressure field and the bottom hole flow pressure of the target fracturing well section.

[0055] Optionally, determining the second fracture spacing according to the distribution of isobars in the effective seepage pressure field and the bottom hole flow pressure of the target fracturing well section includes:

[0056] Substituting the bottom hole flow pressure of the target fracturing well section into the isobar morphology distribution function to obtain the values ​​of ζ and ω in the coordinates (ζ, ω) in the elliptical coordinate system corresponding to the effective seepage pressure field;

[0057] Determine the value of y in the effective seepage pressure field (x2, y) according to the coordinates (ζ, ω) in the elliptical coordinate system;

[0058] The second gap spacing is determined according to the following formula:

[0059] D max =y

[0060] Among them, D max is the second slit spacing, m.

[0061] Another aspect of the present application is to provide a device for determining the density of fracture distribution in a horizontal well of a tight sandstone gas reservoir, the device comprising:

[0062] An acquisition unit is used to obtain ground stress data, basic rock mechanics parameters and core permeability of the rock formation where the target fracturing well section is located;

[0063] A calculation unit, used for calculating the first fracture spacing of the target fracturing well section according to the ground stress data and the rock mechanics basic parameters;

[0064] The calculation unit is further used to calculate the second fracture spacing of the target fracturing well section according to the core permeability;

[0065] A determination unit is used to determine the seam density of the target fracturing well section based on the length of the target fracturing well section, the first seam spacing and the second seam spacing.

[0066] The beneficial effects of the embodiments of the present application are at least:

[0067] The method for determining the density of horizontal well fracturing seams in a tight sandstone gas reservoir provided in the embodiment of the present application first calculates the minimum seam spacing of the target fracturing well under the induced stress field and the minimum seam spacing under the effective seepage pressure field, wherein the minimum seam spacing under the induced stress field is the first seam spacing determined according to the ground stress data and the basic parameters of rock mechanics of the rock formation where the target fracturing well section is located, and the minimum seam spacing under the effective seepage pressure field is the second seam spacing determined according to the core permeability of the rock formation where the target fracturing well section is located; then, according to the length of the target fracturing well section, and the relative size of the first seam spacing and the second seam spacing, the seam density matching the rock formation conditions is calculated. Therefore, this method overcomes the inconvenience and objectivity caused by relying on field tests and experience judgments in the relevant technology to determine the seam density, improves the applicability of the high-density multi-seam fracturing process of horizontal wells, and provides a scientific basis for the formulation and design of subsequent reservoir transformation plans. BRIEF DESCRIPTION OF THE DRAWINGS

[0068] In order to more clearly illustrate the technical solutions in the embodiments of the present application, the drawings required for use in the description of the embodiments will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present application. For ordinary technicians in this field, other drawings can be obtained based on these drawings without creative work.

[0069] Figure 1 This is a flow chart of a method for determining the density of horizontal well fracturing in a tight sandstone gas reservoir provided in an embodiment of the present application;

[0070] Figure 2 This is a flow chart of another method for determining the density of horizontal well fracturing in a tight sandstone gas reservoir provided in an embodiment of the present application;

[0071] Figure 3 It is a schematic diagram of the induced stress field generated in the crack width direction after the crack opens;

[0072] Figure 4 It is a schematic cross-sectional view of a single crack in the crack width direction;

[0073] Figure 5 It is a schematic diagram of the linear seepage pressure boundary distribution of each fracture in some well sections when the transformation is reasonable;

[0074] Figure 6 It is a schematic diagram of the linear seepage pressure boundary distribution of each fracture in some well sections during over-construction;

[0075] Figure 7 It is a schematic diagram of the linear seepage pressure boundary distribution of each fracture in some well sections when the transformation is insufficient;

[0076] Figure 8It is a schematic diagram of the elliptical coordinates of the controllable linear seepage pressure boundary of a single fracture.

[0077] Reference numerals:

[0078] 1. Hydraulic fractures; 2. Small cracks; 3. Strata.

[0079] The above drawings have shown clear embodiments of the present application, which will be described in more detail later. These drawings and text descriptions are not intended to limit the scope of the present application in any way, but to illustrate the concept of the present application to those skilled in the art by referring to specific embodiments. DETAILED DESCRIPTION

[0080] The following will be combined with the drawings in the embodiments of the present application to clearly and completely describe the technical solutions in the embodiments of the present application. Obviously, the described embodiments are part of the embodiments of the present application, not all of the embodiments. Based on the embodiments in the present application, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of this application.

[0081] An embodiment of the present application provides a method for determining the density of fracture distribution in horizontal wells of tight sandstone gas reservoirs. The executor of the method may be a computer device, which may be a terminal, a server, a processor, or any type of data processing device with data processing capabilities.

[0082] like Figure 1 As shown, the method for determining the density of fracturing seams in a horizontal well of a tight sandstone gas reservoir provided in an embodiment of the present application comprises the following steps:

[0083] Step 101, obtaining the ground stress data, basic rock mechanics parameters and core permeability of the rock formation where the target fracturing well section is located;

[0084] Step 102, calculating the first fracture spacing of the target fracturing well section according to the ground stress data and basic rock mechanics parameters;

[0085] Step 103, calculating the second fracture spacing of the target fracturing well section according to the core permeability;

[0086] Step 104: Determine the density of the target fracturing well section based on the length of the target fracturing well section, the first fracture spacing, and the second fracture spacing.

[0087] The method for determining the density of fracture distribution in horizontal wells of tight sandstone gas reservoirs provided in the embodiment of the present application is to construct an induced stress field through data such as the ground stress data and basic rock mechanics parameters of the rock formation where the target fracture section is located, and calculate the minimum fracture distribution spacing under the induced stress field: the first fracture distribution spacing; construct an effective seepage pressure field through data such as the core permeability of the rock formation where the target fracture section is located, and calculate the fracture distribution spacing that can meet the seepage requirements stimulated by the cracks under the effective seepage pressure field: the second fracture distribution spacing; then determine the geological characteristics of the rock formation where the target fracture section is located based on the first fracture distribution spacing and the second fracture distribution spacing, and determine a reasonable fracture distribution density. This method overcomes the inconvenience and objectivity caused by relying on field tests and empirical judgments in related technologies to determine the fracture distribution density, improves the applicability of high-density multi-fracture fracturing technology for horizontal wells, and provides a scientific basis for the formulation and design of subsequent reservoir transformation plans.

[0088] Figure 2 This is a flowchart of another method for determining the density of horizontal well fracturing in a tight sandstone gas reservoir provided in an embodiment of the present application. The method can be executed by a computer device, which can be a terminal, a server, a processor, or any type of data processing device with data processing functions. The present application embodiment uses a terminal as the execution subject to describe the method in detail.

[0089] like Figure 2 As shown, the method may include the following steps:

[0090] Step 201: Obtaining the ground stress data and basic rock mechanics parameters of the rock formation where the target fracturing well section is located.

[0091] In the embodiment of the present application, the geostress data may include the minimum horizontal principal stress of the formation, and the rock mechanics parameters may include elastic modulus, Poisson's ratio and tensile strength.

[0092] For example, the geostress data and rock mechanics basic parameters of the rock formation where the target fracturing well section is located can be obtained by collecting logging data or field survey. The specific steps of obtaining the geostress data and rock mechanics basic parameters of the rock formation where the target fracturing well section is located by collecting logging data can include steps 2011-2013.

[0093] Step 2011: Obtain logging data of the target fracturing well section.

[0094] Well logging data, also known as well logging information, refers to various well logging data obtained by various logging methods in the field of oil and gas exploration, including but not limited to resistivity, natural potential, acoustic wave velocity, rock volume density and other parameters. These well logging data in the well logging data can be used for detailed geological structure and fault research of oil and gas reservoirs.

[0095] Step 2012: interpret the logging data.

[0096] After obtaining the logging data, the logging data can be processed and analyzed, and an interpretation model can be established to establish a qualitative or quantitative connection between the logging data and the actual production data, thereby giving the logging data a direct geological meaning. For example, the result of interpreting the logging data can be in the form of a single or combined logging curve, establishing a variety of practical models or a series of corresponding empirical expressions, which are used to directly describe specific geological phenomena, reservoir rock characteristics, and fluid properties.

[0097] Step 2013: Based on the well logging data interpretation data, the geostress data and basic rock mechanics parameters of the target fracturing well section are obtained.

[0098] In some embodiments of the present application, the geostress profile and the fracture pressure profile can be drawn based on the well logging data interpretation data, and then the minimum horizontal principal stress can be determined from the geostress profile and the fracture pressure profile.

[0099] Step 202: Calculate the first fracture spacing of the target fracturing well section according to the geostress data and basic rock mechanics parameters.

[0100] like Figure 3 As shown in the figure, after the hydraulic fracture 1 in the formation 3 is opened and extends a certain distance along the direction of the maximum horizontal principal stress, local induced stress will be generated in the fracture width direction (the direction of the induced stress is shown in Figure 3 As shown by the arrow in the figure). This induced stress is mainly caused by hydraulic pressure squeezing the cracks outward, causing the cracks to further crack to a certain width. After the hydraulic fracture 1 is squeezed and cracked, it will inevitably produce a squeezing effect on the surrounding strata, thereby changing the original stress state, which is usually manifested as an increase in the value of the ground stress in the fracture width direction. Under the action of local induced stress, the subsequent small fractures 2 that have not yet cracked or have just cracked but have not yet extended will become more difficult to crack or extend due to the squeezing effect of other hydraulic fractures 1 that have already cracked. Even if these small fractures 2 can extend, the final fracture length and width will inevitably be smaller than the hydraulic fracture 1 formed earlier due to suppression. This phenomenon is called the stress shadow effect caused by fracture induced stress. This effect is particularly prominent under the high-density fracture fracturing process. If it is not controlled, some fractures will be difficult to extend or even not extend or crack, which will seriously affect the production of a single well.

[0101] In the embodiment of the present application, the basic theory of geomechanics is used to calculate the degree and range of influence of the stress shadow effect, so as to determine the minimum seam spacing considering the influence of induced stress, that is, the first seam spacing.

[0102] The calculation process of the first gap spacing may include the following steps:

[0103] Step 2021, construct an induced stress field, and calculate the induced stress at any point (x1, z) in the induced stress field using the stress-strain constitutive equation.

[0104] Assuming that there is a symmetrical double-wing vertical fracture in an infinite reservoir, the stress field induced by hydraulic fracture belongs to a plane strain problem. Figure 4 The coordinate system constructed based on the cross section of the vertical crack in the width direction is shown, where the z direction represents the height direction of the crack and the x direction represents the width direction of the crack. According to the constitutive equation of the plane strain problem, the induced stress at any point (x1, z) in the induced stress field can be obtained as:

[0105]

[0106]

[0107] Where:

[0108]

[0109]

[0110] Among them, Δσ x is the horizontal induced stress, Pa; Δσ z is the vertical induced stress, Pa; p is the flow pressure in the wellbore, Pa; H is the fracture height, m; c is the half fracture height, m.

[0111] Step 2022: Calculate the horizontal induced superimposed stress at any point (x1, z) in the induced stress field based on the horizontal induced stress and ground stress data.

[0112] In the embodiment of the present application, the force received by any point in the induced stress field is the superimposed stress of the geostress and the induced stress at the point. Therefore, when calculating the horizontal induced superimposed stress at any point (x1, z) in the induced stress field, it is necessary to obtain the geostress data obtained in step 2013 and the horizontal induced stress received by the point obtained in step 2021, and calculate according to the following formula:

[0113]

[0114] Among them, σ X is the horizontal induced superimposed stress, Pa; σ min is the minimum horizontal principal stress, Pa.

[0115] This step can calculate the horizontal induced superimposed stress at various locations with different hydraulic fracture spacing in the horizontal direction (i.e., the x direction). It should be noted that, when calculating the influence of the horizontal induced superimposed stress, any point (x1, z) will usually only produce displacement in the horizontal direction (i.e., the x direction) but not in the vertical direction (i.e., the z direction), so z=0 can be set in the calculation.

[0116] Step 2023: When the horizontal induced superposition stress meets a preset condition, determine the first seam spacing.

[0117] In the embodiment of the present application, when the calculated horizontal induced superposition stress at a certain position (x1, 0) satisfies the preset condition, the distance x1 at this time can be determined to be the minimum value of the gap spacing, that is, the first gap spacing. The preset condition can be σ X =3S T +σ min .

[0118] That is, in some implementations of the embodiments of the present application, when the horizontal induced superposition stress satisfies σ X =3S T +σ min When , the value of x1 in (x1, 0) corresponding to the horizontal induced stress can be calculated.

[0119] Determine the first gap spacing according to the following formula:

[0120] J min =x1

[0121] Among them, S T is the tensile strength, Pa; J min is the first seam spacing, m.

[0122] Step 203: Obtain the core permeability of the rock formation where the target fracturing well section is located.

[0123] Core refers to a cylindrical rock sample taken from a borehole using an annular core drill bit and other coring tools. The core permeability can include vertical permeability and horizontal permeability. The vertical permeability refers to the permeability in the length direction of the vertical crack, and the horizontal permeability refers to the permeability in the width direction of the vertical crack. Figure 4 Taking the vertical fracture shown as an example, when determining the core permeability, the horizontal permeability of the rock layer where the fracture is located is usually determined.

[0124] In some implementations of the embodiments of the present application, step 203 may specifically include:

[0125] Step 2031: Obtain a full-diameter core in the target fracturing section.

[0126] Full-diameter core refers to a columnar core taken from an oil (gas) layer by coring technology, without cutting or splitting, and used in the laboratory for analysis and determination of relevant parameters. It can be used to obtain core characteristic data in the horizontal direction of the oil (gas) layer, such as horizontal permeability, porosity, and oil, gas, and water saturation.

[0127] Step 2032: Obtain a standard core plug based on the full-diameter core and measure the core permeability of the standard core plug.

[0128] Standard core plugs refer to standard core columns with a diameter of 25 mm drilled from full-diameter cores according to certain requirements. They are standard samples for measuring rock parameters such as porosity and permeability. Multiple standard core plugs can be drilled from a full-diameter core.

[0129] When measuring the core permeability, in order to improve the accuracy of the measurement results, the method of taking the average value of multiple measurements can be adopted.

[0130] Step 204: Calculate the second fracture spacing of the target fracturing well section according to the core permeability.

[0131] The ultimate purpose of forming hydraulic fractures during reservoir transformation construction is to increase the area of ​​linear seepage in the formation with the help of the continuous expansion of the fracture surface, thereby improving the seepage environment of the formation fluid. Therefore, after the fracturing construction is completed, a certain range of hydraulic fracture controllable linear seepage pressure boundary will be formed around each artificial fracture. The boundary line of this area is mainly linear seepage. Compared with the radial seepage of the wellbore before the transformation, under the same seepage pressure, the flow rate of the formation fluid that can pass through the boundary line of this area is greatly increased, which significantly improves the production efficiency of the formation fluid. On the other hand, since the controllable linear seepage pressure boundary of the hydraulic fracture is not infinite, that is, the formation fluid seepage in the area away from the artificial fracture at a certain distance is still difficult to participate in the linear seepage, then it is necessary to form another artificial fracture to densify the area.

[0132] The controllable linear seepage pressure boundary of the fracture determines the reasonable location of the fracture to a certain extent. Figure 5 The figure shows the distribution of linear seepage pressure boundary under reasonable transformation of seam density. However, if the transformation is excessive, such as Figure 6 As shown in the figure, if the density of cracks is too high, it will easily lead to a waste of cost, and may also produce a strong stress shadow effect between cracks due to the high density of cracks, resulting in some cracks being inhibited from fully expanding, which will reduce the linear seepage pressure boundary. Figure 7 As shown in the figure, the density of seams is low at this time, which will leave unused areas and reduce the single well production capacity.

[0133] Therefore, calculating the linear seepage pressure boundary is the key to rationalizing the density of fractures in reservoir reconstruction. Since the conductivity of fractures along the length of the fracture is different, the low linear seepage pressure boundary theoretically presents a series of isobaric ellipses. Therefore, the constructed effective seepage pressure field is as follows: Figure 8 shown.

[0134] In the embodiment of the present application, the calculation process of the minimum spacing between seams under the effective seepage pressure field, that is, the second spacing between seams, may include the following steps:

[0135] Step 2041, construct an effective seepage pressure field, and determine any point (x2, y) in the effective seepage pressure field.

[0136] Figure 8 The elliptical coordinate system constructed based on the cross section of the vertical crack in the length direction is shown, where the y direction represents the length direction of the crack and the x direction represents the width direction of the crack. Based on this, any point (x2, y) in the effective seepage pressure field can be expressed in the following way:

[0137]

[0138] Among them, (ζ, ω) is the coordinate of (x2, y) in the elliptical coordinate system corresponding to the effective seepage pressure field; a and b are the major axis and minor axis of the ellipse corresponding to (ζ, ω), respectively, and the direction of the minor axis is parallel to the gas seepage direction; c is the half-crack height, m.

[0139] Step 2042: determine the isobar morphology distribution function in the effective seepage pressure field.

[0140] In the embodiment of the present application, the isobar morphology distribution function can be expressed as:

[0141]

[0142] In the formula,

[0143]

[0144] Where p is the fluid flow pressure at the fracture, Pa; p wf is the bottom hole pressure, Pa; μ is the fluid viscosity, Pa·s; Z is the compressibility factor of the fluid under reservoir conditions; T is the reservoir temperature, K; k is the permeability, D; q s is the wellhead fluid flow rate, m 3 / s;p s is the wellhead pressure, MPa; H is the fracture height, m; T s is the wellhead temperature, K; Z s is the gas compressibility factor.

[0145] Step 2043: Determine the second fracture spacing according to the distribution of isobars in the effective seepage pressure field and the bottom hole flow pressure of the target fracturing well section.

[0146] In some implementations of the embodiments of the present application, the bottom hole flow pressure of the target fracturing section can be substituted into the isobar morphology distribution function to obtain the values ​​of ζ and ω in the coordinates (ζ, ω) in the elliptical coordinate system corresponding to the effective seepage pressure field; then, the value of y in (x2, y) in the effective seepage pressure field is determined according to the coordinates (ζ, ω) in the elliptical coordinate system; finally, the second seam spacing is determined according to the following formula.

[0147] Among them, according to different production requirements, technicians can customize the bottom hole flow pressure p wf , and then calculate the isobars under different expected production systems to determine whether the effective seepage field stimulated by the hydraulic fractures can completely cover all well sections. For example, when the bottom hole pressure is determined to be p wf When the hydraulic fracture activates the boundary that meets the seepage requirements, the distance from the fracture center is y = D max .

[0148] Therefore, in the embodiment of the present application, the formula for determining the second gap spacing may be set as:

[0149] D max =y

[0150] Among them, D max Represents the second slit spacing, m.

[0151] It should be noted that in the embodiment of the present application, the order of steps 201-202 and steps 203-204 can be swapped, that is, steps 203-204 can be performed first, and then steps 201-202; or, steps 201-202 and steps 203-204 can be performed at the same time.

[0152] Step 205: Obtain the length of the target fracturing well section.

[0153] For example, the length of the target fracturing section can be obtained from drilling data or through field measurement.

[0154] After the length of the target fracturing section is obtained, step 206 is executed.

[0155] Step 206: Determine the density of the target fracturing well section based on the length of the target fracturing well section, the first fracture spacing, and the second fracture spacing.

[0156] In step 202 and step 204, the minimum seam spacing of the target fracturing well under the induced stress field and the minimum seam spacing under the effective seepage pressure field have been calculated respectively. In order to formulate a reasonable seam density, it is necessary to compare the first seam spacing and the second seam spacing.

[0157] When the first seam spacing is greater than the second seam spacing, it means that the rock is harder and a small amount of displacement can easily lead to a larger oil channel stress field. The minimum seam spacing should be designed according to the first seam spacing to ensure that the cracks can expand evenly. The seam density at this time is:

[0158] s=L / J min

[0159] Where s is the density of the fractures; L is the length of the target fracturing section, m; J min is the first seam spacing, m.

[0160] When the first slit spacing is smaller than the second slit spacing, it means that the reservoir matrix has better seepage conditions, or the fracture conductivity is higher, which can stimulate a larger range of effective seepage fields. In order to save costs, the slit positions should be designed according to the second slit spacing. The slit density at this time is:

[0161] s=L / D max

[0162] Where s is the density of the seams; L is the length of the target fracturing section, m; D max is the second slit spacing, m.

[0163] In summary, the method for determining the density of horizontal well fracturing seams in tight sandstone gas reservoirs provided in the embodiment of the present application first calculates the minimum seam spacing of the target fracturing well under the induced stress field and the minimum seam spacing under the effective seepage pressure field, wherein the minimum seam spacing under the induced stress field is the first seam spacing determined according to the geostress data and basic rock mechanics parameters of the rock formation where the target fracturing well section is located, and the minimum seam spacing under the effective seepage pressure field is the second seam spacing determined according to the core permeability of the rock formation where the target fracturing well section is located; then, according to the length of the target fracturing well section, and the relative size of the first seam spacing and the second seam spacing, the seam density matching the rock formation conditions is calculated. Therefore, this method overcomes the inconvenience and objectivity caused by relying on field tests and empirical judgments to determine the seam density in the related art, improves the applicability of the high-density multi-seam fracturing process of horizontal wells, and provides a scientific basis for the formulation and design of subsequent reservoir transformation plans. At the same time, this method also comprehensively considers the characteristics of fracture extension and diversion under the induced stress field and effective seepage pressure field. The calculated fracture density is more scientific and reasonable, and also improves the universality of the high-density multi-fracture fracturing technology for horizontal wells.

[0164] The present application also provides a device for determining the density of horizontal well fracturing in a tight sandstone gas reservoir, which can be installed on a computer device. In the present application, the device can include:

[0165] An acquisition unit is used to obtain ground stress data, basic rock mechanics parameters and core permeability of the rock formation where the target fracturing well section is located;

[0166] A calculation unit, used for calculating the first seam spacing of the target fracturing well section according to the ground stress data and the basic parameters of rock mechanics;

[0167] The calculation unit is also used to calculate the second fracture spacing of the target fracturing well section according to the core permeability;

[0168] A determination unit is used to determine the seam density of the target fracturing well section based on the length of the target fracturing well section, the first seam spacing and the second seam spacing.

[0169] Therefore, in the device for determining the density of horizontal well fracturing seams in tight sandstone gas reservoirs provided in the embodiment of the present application, the calculation unit can respectively calculate the minimum seam spacing of the target fracturing well under the induced stress field and the minimum seam spacing under the effective seepage pressure field, wherein the minimum seam spacing under the induced stress field is the first seam spacing determined according to the ground stress data of the rock formation where the target fracturing well section is located obtained by the acquisition unit and the basic parameters of rock mechanics, and the minimum seam spacing under the effective seepage pressure field is the second seam spacing determined according to the core permeability of the rock formation where the target fracturing well section is located obtained by the acquisition unit; then the determination unit will calculate the seam density that matches the rock formation conditions according to the length of the target fracturing well section and the relative sizes of the first seam spacing and the second seam spacing. Therefore, the use of this device to design the seam position can overcome the inconvenience and objectivity caused by relying on field tests and experience judgments in the relevant technology to determine the seam density, improve the applicability of the high-density multi-seam fracturing process of horizontal wells, and provide a scientific basis for the formulation and design of subsequent reservoir transformation plans.

[0170] The present application also provides another device for determining the density of horizontal well fracturing in a tight sandstone gas reservoir. The device can be installed on a computer device. The device can include:

[0171] The acquisition unit is used to obtain the ground stress data, basic rock mechanics parameters and core permeability of the rock formation where the target fracturing well section is located.

[0172] In some implementations of the embodiments of the present application, the acquiring unit may include:

[0173] A first acquisition module is used to acquire logging data of a target fracturing well section;

[0174] The data processing module is used to interpret the logging data and obtain the logging data interpretation data; it is also used to obtain the geostress data and basic rock mechanics parameters of the target fracturing section based on the logging data interpretation data. Among them, the geostress data includes the minimum horizontal principal stress of the formation, and the basic rock mechanics parameters include elastic modulus, Poisson's ratio and tensile strength.

[0175] The drawing module is used to draw a geostress profile and a fracture pressure profile based on the well logging data interpretation data.

[0176] The second acquisition module is used to acquire a full-diameter core in a target fracturing well section, and acquire a standard core plunger based on the full-diameter core, and measure the core permeability of the standard core plunger.

[0177] The calculation unit is used to calculate the first seam spacing of the target fracturing well section according to the ground stress data and the basic parameters of rock mechanics.

[0178] In some implementations of the embodiments of the present application, the calculation unit may include:

[0179] The first model building module is used to construct the induced stress field and determine the induced stress at any point (x1, z) in the induced stress field according to the following formula:

[0180]

[0181]

[0182] Where:

[0183]

[0184]

[0185] Among them, Δσ x is the horizontal induced stress, Pa; Δσ z is the vertical induced stress, Pa; p is the flow pressure in the wellbore, Pa; c is the half-fracture height, m.

[0186] The first calculation module is used to calculate the horizontal induced superimposed stress at any point (x1, z) in the induced stress field based on the horizontal induced stress and the geostress data according to the following formula:

[0187]

[0188] Among them, σ X is the horizontal induced superimposed stress, Pa; σ min is the minimum horizontal principal stress, Pa.

[0189] The first determination module is used to determine the first seam spacing when the horizontal induced superposition stress meets a preset condition.

[0190] The calculation unit is also used to calculate the second fracture spacing of the target fracturing well section according to the core permeability.

[0191] In some implementations of the embodiments of the present application, the calculation unit may further include:

[0192] The second model building module is used to build an effective seepage pressure field and determine the coordinates (x2, y) of any point in the effective seepage pressure field:

[0193]

[0194] Wherein, (ζ, ω) is the coordinate of (x2, y) in the elliptical coordinate system corresponding to the effective seepage pressure field; a and b are the major axis and minor axis of the ellipse corresponding to (ζ, ω), respectively, and the direction of the minor axis is parallel to the gas seepage direction; c is the half-crack height, m;

[0195] The second calculation module is used to calculate the isobaric shape distribution function in the effective seepage pressure field:

[0196]

[0197] In the formula,

[0198]

[0199] Where p is the fluid flow pressure at the fracture, Pa; p wf is the bottom hole pressure, Pa; μ is the fluid viscosity, Pa·s; Z is the compressibility factor of the fluid under reservoir conditions; T is the reservoir temperature, K; k is the permeability, D; q s is the wellhead fluid flow rate, m 3 / s;p s is the wellhead pressure, MPa; H is the fracture height, m; T s is the wellhead temperature, K; Z s is the gas compressibility factor.

[0200] The second determination module is used to determine the second fracture spacing according to the distribution of isobars in the effective seepage pressure field and the bottom hole flow pressure of the target fracturing well section.

[0201] The determination unit is used to determine the fracture density of the target fracturing well section based on the length of the target fracturing well section, the first fracture spacing and the second fracture spacing.

[0202] In some implementations of the embodiments of the present application, the determining unit may include:

[0203] A third acquisition module is used to obtain the length of the target fracturing well section;

[0204] The comparison module is used to compare the first seam spacing and the second seam spacing. When the first seam spacing is greater than the second seam spacing, the seam density is calculated by the following formula:

[0205] s=L / J min

[0206] When the first seam spacing is smaller than the second seam spacing, the seam density is calculated by the following formula:

[0207] s=L / D max

[0208] Where s is the density of the fractures; L is the length of the target fracturing section, m; J min is the first seam spacing, m; D max is the second slit spacing, m.

[0209] Regarding the device in the above embodiment, the specific manner in which each unit and module performs operations has been described in detail in the embodiment of the method, and will not be elaborated here.

[0210] The embodiment of the present application provides a device for determining the density of fracture distribution of horizontal wells in a tight sandstone gas reservoir, comprising: a processor and a memory,

[0211] Memory for storing computer programs;

[0212] A processor is used to execute a computer program stored in the memory to implement the following Figure 1 or Figure 2 The method for determining the density of fracture distribution in horizontal wells in tight sandstone gas reservoirs is shown.

[0213] The present application provides a storage medium, which, when a program in the storage medium is executed by a processor, can achieve the following Figure 1 or Figure 2 The method for determining the density of fracture distribution in horizontal wells in tight sandstone gas reservoirs is shown.

[0214] A person skilled in the art will understand that all or part of the steps to implement the above embodiments may be accomplished by hardware or by instructing related hardware through a program, and the program may be stored in a computer-readable storage medium, and the above-mentioned storage medium may be a read-only memory, a disk or an optical disk, etc.

[0215] In order to make the technical solutions and advantages of the present application more clear, they will be described in detail below through optional embodiments.

[0216] The method for determining the density of fracturing seams in horizontal wells of tight sandstone gas reservoirs provided in the embodiment of the present application has been applied to a development well of a tight sandstone gas reservoir on land in a certain place, wherein the length of the fracturing construction section of the development well of the tight sandstone gas reservoir is 566m, the vertical thickness of the reservoir is 21.1m, the horizontal section reservoir length is 448.3m, the average porosity is 9.6%, the permeability is 0.53mD, and the gas saturation is 81.3%. The planned construction displacement is 14-16m 3 / min, the average length of the transformation section is about 60m, the liquid system is slick water, a total of 2,363 tons of proppant are transported, and the planned test output after the transformation is completed is 100,000 cubic meters / day.

[0217] According to the above method, it can be calculated that the reasonable seam density of the well is 8 to 10 meters per seam, and the determined seam layout plan is shown in Table 1.

[0218] Table 1. Development well layout plan for a tight sandstone gas reservoir on land in a certain place

[0219]

[0220] The production logging results after transformation are shown in Table 2. It can be seen that all perforations in the well contribute to gas production, which indicates that the perforation opening rate is 100%, the fracture initiation efficiency is 100%, and the actual production has reached the planned production.

[0221] Table 2. Gas production contribution rate of each perforation cluster after transformation

[0222]

[0223]

[0224] In the present application, it should be understood that the terms "first", "second", "third", etc. are used for descriptive purposes only and cannot be understood as indicating or implying relative importance or implicitly indicating the number of the indicated technical features.

[0225] Those skilled in the art will readily appreciate other embodiments of the present application after considering the specification and practicing the present application disclosed herein. The present application is intended to cover any variations, uses or adaptations of the present application, which follow the general principles of the present application and include common knowledge or customary techniques in the art that are not disclosed in the present application. The specification and examples are intended to be exemplary only.

[0226] It should be understood that the present application is not limited to the precise structures that have been described above and shown in the drawings, and that various modifications and changes may be made without departing from the scope thereof. The scope of the present application is limited only by the appended claims.

Claims

1. A method for determining the density of horizontal well fracturing in a tight sandstone gas reservoir, characterized in that: The method comprises: Obtaining geostress data, basic rock mechanics parameters and core permeability of the rock formation where the target fracturing well section is located; wherein the core permeability is obtained by the following method: obtaining a full-diameter core in the target fracturing well section; obtaining a standard core plunger based on the full-diameter core, and measuring the core permeability of the standard core plunger; The induced stress field is constructed, and the induced stress at any point (x1, z) in the induced stress field is calculated by the stress-strain constitutive equation: Where: Among them, Δσ x is the horizontal induced stress, Pa; Δσ z is the vertical induced stress, Pa; p is the flow pressure in the wellbore, Pa; c is the half fracture height, m; Based on the horizontal induced stress and the geostress data, the horizontal induced superimposed stress at any point (x1, z) in the induced stress field is calculated: Among them, σ X is the horizontal induced superimposed stress, Pa; σ min is the minimum horizontal principal stress, Pa; When the horizontal induced superimposed stress satisfies σ X =3S T +σ min , calculate the value of x1 in (x1, 0) corresponding to the horizontal induced stress; Determine the first gap spacing according to the following formula: J min =x1 Among them, S T is the tensile strength, Pa; J min is the first seam spacing, m; Construct an effective seepage pressure field and determine any point (x2, y) in the effective seepage pressure field: Wherein, (ζ, ω) is the coordinate of (x2, y) in the elliptical coordinate system corresponding to the effective seepage pressure field; a and b are the major axis and minor axis of the ellipse corresponding to (ζ, ω), respectively, and the direction of the minor axis is parallel to the gas seepage direction; c is the half-crack height, m; Determine the isobar morphology distribution function in the effective seepage pressure field: In the formula, Where p is the fluid flow pressure at the fracture, Pa; p wf is the bottom hole pressure, Pa; μ is the fluid viscosity, Pa·s; Z is the compressibility factor of the fluid under reservoir conditions; T is the reservoir temperature, K; k is the permeability, D; q s is the wellhead fluid flow rate, m 3 / s;p s is the wellhead pressure, MPa; H is the fracture height, m; T s is the wellhead temperature, K; Z s is the gas compressibility factor; Substituting the bottom hole flow pressure of the target fracturing well section into the isobar morphology distribution function to obtain the values ​​of ζ and ω in the coordinates (ζ, ω) in the elliptical coordinate system corresponding to the effective seepage pressure field; Determine the value of y in the effective seepage pressure field (x2, y) according to the coordinates (ζ, ω) in the elliptical coordinate system; The second gap spacing is determined according to the following formula: D max =y Among them, D max is the second seam spacing, m; Obtaining the length of the target fracturing well section; The first seam spacing and the second seam spacing are compared, wherein when the first seam spacing is greater than the second seam spacing, the seam density is calculated by the following formula: S=L / J min When the first seam spacing is smaller than the second seam spacing, the seam density is calculated by the following formula: s=L / D max Where s is the density of the fractures; L is the length of the target fracturing section, m; J min is the first seam spacing, m; D max is the second slit spacing, m.

2. The method according to claim 1, characterized in that: The acquisition of ground stress data and basic rock mechanics parameters of the rock formation where the target fracturing well section is located includes: Acquiring logging data of the target fracturing well section and interpreting the logging data; Based on the interpretation data of the logging data, the geostress data and basic rock mechanics parameters of the target fracturing section are obtained. The geostress data include the minimum horizontal principal stress of the formation, and the basic rock mechanics parameters include elastic modulus, Poisson's ratio and tensile strength.

3. The method according to claim 2, characterized in that The method of interpreting the data based on the well logging data to obtain the geostress data of the target fracturing well section includes: Based on the well logging data interpretation data, draw a geostress profile and a fracture pressure profile; The minimum horizontal principal stress is determined from the in-situ stress profile and the fracture pressure profile.

4. A device for determining the density of fracturing seams in horizontal wells of tight sandstone gas reservoirs, characterized in that: The device comprises: An acquisition unit is used to acquire the ground stress data, basic rock mechanics parameters and core permeability of the rock formation where the target fracturing well section is located; wherein the core permeability is acquired by the following method: acquiring a full-diameter core in the target fracturing well section, acquiring a standard core plunger based on the full-diameter core, and measuring the core permeability of the standard core plunger; Computing unit for: The induced stress field is constructed, and the induced stress at any point (x1, z) in the induced stress field is calculated by the stress-strain constitutive equation: Where: Among them, Δσ x is the horizontal induced stress, Pa; Δσ z is the vertical induced stress, Pa; p is the flow pressure in the wellbore, Pa; c is the half fracture height, m; Based on the horizontal induced stress and the geostress data, the horizontal induced superimposed stress at any point (x1, z) in the induced stress field is calculated: Among them, σ X is the horizontal induced superimposed stress, Pa; σ min is the minimum horizontal principal stress, Pa; When the horizontal induced superimposed stress satisfies σ X =3S T +σ min , calculate the value of x1 in (x1, 0) corresponding to the horizontal induced stress; Determine the first gap spacing according to the following formula: J min =x1 Among them, S T is the tensile strength, Pa; J min is the first seam spacing, m; The computing unit is further used for: Construct an effective seepage pressure field and determine any point (x2, y) in the effective seepage pressure field: Wherein, (ζ, ω) is the coordinate of (x2, y) in the elliptical coordinate system corresponding to the effective seepage pressure field; a and b are the major axis and minor axis of the ellipse corresponding to (ζ, ω), respectively, and the direction of the minor axis is parallel to the gas seepage direction; c is the half-crack height, m; Determine the isobar morphology distribution function in the effective seepage pressure field: In the formula, Where p is the fluid flow pressure at the fracture, Pa; p wf is the bottom hole pressure, Pa; μ is the fluid viscosity, Pa·s; Z is the compressibility factor of the fluid under reservoir conditions; T is the reservoir temperature, K; k is the permeability, D; q s is the wellhead fluid flow rate, m 3 / s;p s is the wellhead pressure, MPa; H is the fracture height, m; T s is the wellhead temperature, K; Z s is the gas compressibility factor; Substituting the bottom hole flow pressure of the target fracturing well section into the isobar morphology distribution function to obtain the values ​​of ζ and ω in the coordinates (ζ, ω) in the elliptical coordinate system corresponding to the effective seepage pressure field; Determine the value of y in the effective seepage pressure field (x2, y) according to the coordinates (ζ, ω) in the elliptical coordinate system; The second gap spacing is determined according to the following formula: D max =y Among them, D max is the second seam spacing, m; Identify units for: Obtaining the length of the target fracturing well section; The first seam spacing and the second seam spacing are compared, wherein when the first seam spacing is greater than the second seam spacing, the seam density is calculated by the following formula: s=L / J min When the first seam spacing is smaller than the second seam spacing, the seam density is calculated by the following formula: s=L / D max Where s is the density of the fractures; L is the length of the target fracturing section, m; J min is the first seam spacing, m; D max is the second slit spacing, m.

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