Calculation method for predicting hydraulic fracturing bursting pressure of hydrate reservoir vertical well

Abstract

The invention discloses a calculation method for predicting hydraulic fracturing bursting pressure of a hydrate reservoir vertical well, which comprises the following steps of: constructing an in-situ stress field calculation model based on rock non-linear elastic deformation characteristics; under a polar coordinate system, a well wall main stress calculation model is constructed by considering the induced stress of a drilling well hole in the development process, the induced stress of high-pressure liquid injection and the additional stress increment of stable seepage in a pore medium; dividing into three types of stress modes according to the relative magnitude relation of principal stress; adopting a Mohr-Columb criterion to establish a fracture pressure calculation model of hydrofracture of the hydrate reservoir in the three types of stress modes; the fracture pressure of hydrate reservoir hydraulic fracturing is predicted and determined by checking the stress mode when the hydrate reservoir is fractured, and quantitative prediction of the fracture pressure of hydrate reservoir vertical well hydraulic fracturing is achieved. The technical blank in the field is filled, and technical support is provided for correct design and smooth implementation of the hydrate reservoir.

Description

Technical Field

[0001] The invention relates to a calculation method for predicting hydraulic fracturing fracture pressure of a vertical well in a hydrate reservoir, and belongs to the research field of fracturing development of unconventional oil and gas fields. Background Art

[0002] Natural gas hydrates are considered to be the most promising alternative clean energy in the 21st century. More than 90% of the world's total natural gas hydrates are found in clayey silt or silty sediments on the seafloor. my country is rich in hydrate resources. The prospective resources on the northern slope of the South China Sea alone are close to half of my country's total onshore and offshore oil and gas resources. From 2017 to 2020, my country's trial production of muddy silt-type natural gas hydrates on the northern slope of the South China Sea was successful, proving that sediments in clayey silt on the seafloor are also technically recoverable, but there are still many key technical issues to be solved before industrial exploitation. Although there is no field practice of hydraulic fracturing of hydrate reservoirs in the world, Too et al. confirmed through injection pressure curves that sandy reservoirs with a saturation of 50% to 75% of natural gas hydrates are compressible. my country is also vigorously promoting the exploration of the use of hydraulic fracturing to achieve industrial development of natural gas hydrate reservoirs. In fact, nearly 80 years of mining practice has proven that hydraulic fracturing is a necessary technical measure to achieve effective development of low-permeability reservoirs. In the past 30 years, it has achieved great success in the transformation of unconventional oil and gas reservoirs and changed the world's energy structure. Using hydraulic fracturing to transform natural gas hydrate reservoirs can significantly increase the decomposition area and decomposition rate of natural gas hydrates to increase production, and its future is promising.

[0003] The fracture pressure of reservoir formation is a key parameter that restricts the reasonable configuration of fracturing equipment and the optimization of construction parameters. Traditional fracturing objects are mainly sandstone, carbonate rock, volcanic rock, etc. The industry usually regards them as isotropic homogeneous linear elastic materials and uses the maximum tensile stress strength criterion to predict hydraulic fracturing fracture pressure. For example, Hubbert & Willis first proposed the HW criterion for calculating fracture pressure based on the linear elastic tensile failure theory; Zhou Nayun et al. made a detailed summary of the current formation fracture pressure prediction technology; Wu Feipeng et al. subdivided the elastic mechanics fracture model and the fracture mechanics fracture model, and analyzed the basic assumptions, derivation principles, adaptability and limitations of the existing subdivision models. Since the hydrate reservoir is shallowly buried, the difference in the three-dimensional principal stress is small, and the rock is mainly clayey silt or silty sediment, its deformation characteristics do not meet the current assumption that the reservoir rock mass is regarded as an "isotropic homogeneous linear elastic material", so the aforementioned fracture pressure prediction model and method applicable to it cannot be applied. Summary of the invention

[0004] In order to overcome the defects in the prior art, the present invention aims to provide a calculation method for predicting the hydraulic fracturing pressure of a vertical well in a hydrate reservoir.

[0005] The present invention provides a technical solution to solve the above technical problems: a calculation method for predicting the hydraulic fracturing pressure of a vertical well in a hydrate reservoir, comprising the following steps:

[0006] A. Collect the stress-strain characteristic coefficient, stress-strain characteristic index, Poisson's ratio, cohesion, internal friction angle, rock mass Boit constant and pore fluid pressure of the hydrate reservoir;

[0007] B. Calculate the in-situ stress of the hydrate reservoir based on the strain characteristic index, Poisson's ratio, rock mass Boit constant and pore fluid pressure of the hydrate reservoir;

[0008] C. Calculate the intermediate constants f1, f2, and f4 based on Poisson's ratio, cohesion, internal friction angle, and rock mass Boit constant;

[0009] D. Calculate the coefficient f3 for any polar angle θ from θ = 0° to θ = 90° based on the in situ stress of the hydrate reservoir;

[0010] E. Calculate the fracture pressure of three stress modes of hydrate reservoir fracturing at any polar angle θ respectively;

[0011] F. Calculate the corresponding three-dimensional principal stresses using the fracture pressure under the three stress modes as the injection pressure;

[0012] G. Determine the hydrate reservoir fracturing stress mode based on the three-dimensional principal stresses, and check the corresponding stress mode. The result that is consistent with the stress mode and the response fracture pressure is taken as the true fracture pressure.

[0013] A further technical solution is that the calculation formula in step B is:

[0014]

[0015] Where: k H , k h are the empirical tectonic stress coefficients in the directions of the maximum and minimum principal stresses in the reservoir, dimensionless; α is the Boit constant of the rock mass, dimensionless; p s is the reservoir fluid pressure, MPa; ν is the rock mass Poisson’s ratio, dimensionless; dz is the integral variable, m; L water , L goal is the seawater depth and target reservoir depth, m; ρ water , rock are the density of seawater and local overburden strata that vary with depth, Kg / m 3 ; σ v is the vertical principal stress of the hydrate reservoir, MPa; g is the gravitational acceleration, m / s 2 ; σ his the horizontal component of the in-situ gravity stress of the hydrate reservoir, MPa; σ x , σ y , σ z are the maximum and minimum horizontal principal stresses and vertical principal stress of the reservoir, respectively, in MPa; n is the rock mass stress-strain characteristic index, dimensionless.

[0016] A further technical solution is that the calculation formula in step C is:

[0017]

[0018] Where: C is the cohesion of the rock mass, MPa; φ is the internal friction angle, °; α is the Boit constant of the rock mass, dimensionless; ν is the Poisson's ratio of the rock mass, dimensionless.

[0019] A further technical solution is that the calculation formula in step D is:

[0020] f3=(σ x +σ y )-2(σ x -σ y )cos(2θ)

[0021] Where: x , σ y are the maximum and minimum principal stresses at reservoir level, respectively; θ is the polar angle, °.

[0022] A further technical solution is that the three stress modes of hydrate reservoir fracturing in step E include a first stress mode, a second stress mode, and a third stress mode;

[0023] The calculation formula of the rupture pressure of the first stress mode is:

[0024]

[0025] The calculation formula of the rupture pressure of the second stress mode is:

[0026]

[0027] The calculation formula of the rupture pressure of the third stress mode is:

[0028]

[0029] Where: are the fracture pressure of the first stress mode, the fracture pressure of the second stress mode, and the fracture pressure of the third stress mode respectively; α is the rock mass Boit constant, dimensionless; p s is the reservoir fluid pressure, MPa; σ v is the vertical principal stress of the hydrate reservoir, MPa.

[0030] A further technical solution is that the specific calculation process of the three principal stresses in step F is:

[0031] F1. Calculate the radial and circumferential induced stresses caused by drilling on the wellbore wall based on the in-situ stress of the hydrate reservoir;

[0032] F2. Calculate the additional stress increment on the wellbore wall caused by stable seepage in the porous medium during the fracturing and injection process based on the rock mass Boit constant and the hydrate reservoir pore fluid pressure;

[0033] F3. Calculate the three principal stresses on the well wall based on the principle of stress superposition.

[0034] A further technical solution is that the calculation formula in step F1 is:

[0035]

[0036] Where: r2 , σ θ2 are the radial and circumferential stresses generated by fluid injection into the wellbore, MPa; σ r1 , σ θ1 are the stresses in radial and circumferential directions, MPa; p i is the injection pressure into the wellbore, MPa.

[0037] A further technical solution is that the calculation formula in step F2 is:

[0038]

[0039] Where: r3 , σ θ3 are the radial and circumferential additional stress increments of the wellbore during stable seepage of fracturing injection fluid, MPa; p i is the injection pressure into the wellbore, MPa; p s is the pore fluid pressure in the reservoir, MPa.

[0040] A further technical solution is that the calculation formula in step F3 is:

[0041]

[0042] Where: r , σ θ , σ z are the radial, circumferential and vertical stress components acting on the wellbore wall in the polar coordinate system, MPa; p i is the injection pressure into the wellbore, MPa.

[0043] A further technical solution is that the specific judgment criteria for determining the hydrate reservoir fracturing stress mode according to the three-dimensional principal stress in step G are:

[0044] When σ r >σ z >σ θ When , it is the first stress mode;

[0045] When σ z >σ r >σ θ When , it is the second stress mode;

[0046] When σ r >σ θ >σ z It is the third stress mode.

[0047] The true fracture pressure of the hydrate reservoir is determined by combining the three-dimensional stress pattern and the corresponding fracture pressure consistency.

[0048] The present invention has the following beneficial effects: the present invention takes into account the characteristics of hydrate reservoir media that are different from traditional "isotropic homogeneous linear elastic" media, objectively and correctly reflects the fracture initiation mechanism during hydraulic fracturing of vertical wells in hydrate reservoirs, and fills the gap in this prediction technology. BRIEF DESCRIPTION OF THE DRAWINGS

[0049] Figure 1 It is the stress-strain test curve of hydrate reservoir core;

[0050] Figure 2 is the stress-strain characteristic coefficient and index diagram;

[0051] Figure 3 is the borehole polar coordinate diagram;

[0052] Figure 4 The figure is the calculation result of the hydrate reservoir fracturing pressure changing with the polar angle;

[0053] Figure 5 This is the calculation result diagram of hydrate reservoir fracture pressure;

[0054] Figure 6 This is the three-dimensional stress state diagram when the hydrate reservoir is fractured. DETAILED DESCRIPTION

[0055] The technical solution of the present invention will be described clearly and completely below in conjunction with the accompanying drawings. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0056] A calculation method for predicting the hydraulic fracturing pressure of a vertical well in a hydrate reservoir according to the present invention comprises the following steps:

[0057] A. Collect the stress-strain characteristic coefficient, stress-strain characteristic index, Poisson's ratio, cohesion, internal friction angle, rock mass Boit constant and pore fluid pressure of the hydrate reservoir;

[0058] During the process, core samples of hydrate reservoirs were drilled and the stress-strain curve of the hydrate reservoirs was experimentally tested on a material testing machine according to the national standard "Standard for Engineering Rock Test Methods" (GB / T50266-2013), and the Poisson's ratio was determined based on the definition and experimental curve.

[0059] The strain characteristic coefficient and index are determined by using the regression method according to the stress-strain model shown in formula (1);

[0060]

[0061] Where: E is the elastic modulus of rock mass, MPa; σ and ε are the stress (MPa) and strain (dimensionless) obtained from experimental tests, respectively; b and n are the stress-strain characteristic coefficient and exponent obtained from experimental tests, dimensionless;

[0062] Collect or use indoor core testing to obtain parameters such as hydrate reservoir cohesion and internal friction angle, rock mass Boit constant, etc. The test method is experimentally tested in accordance with the national standard "Engineering Rock Test Method Standard" (GB / T50266-2013);

[0063] Determine the pore fluid pressure of the hydrate reservoir using well logging data or drilling prediction methods or pressure recovery methods;

[0064] B. Calculate the in-situ stress of the hydrate reservoir based on the strain characteristic index, Poisson's ratio, rock mass Boit constant and pore fluid pressure of the hydrate reservoir;

[0065] The in-situ stress of the hydrate reservoir includes three principal stresses, namely vertical stress, maximum horizontal stress and minimum horizontal principal stress. It is composed of the gravity stress field and tectonic stress field under the influence of the pore fluid pressure at that point, and satisfies the superposition principle;

[0066] The vertical principal stress of the hydrate reservoir is calculated using the density of the local overburden and the density of seawater. The density of seawater is obtained by experimental testing (usually about 1025Kg / m 3 ), the density of the overlying rock formation is obtained from the well logging data, and its calculation formula is:

[0067]

[0068] Where: dz is the integral variable, m; L water , L goalis the seawater depth and target reservoir depth, m; ρ water , rock are the density of seawater and local overburden strata that vary with depth, Kg / m 3 ; σ v is the vertical principal stress of the hydrate reservoir, MPa; g is the gravitational acceleration, m / s 2 ;

[0069] According to Terzaghi effective stress theory, based on rock mass stress-strain model, the horizontal component of in-situ gravity stress in hydrate reservoir is calculated according to the generalized Hook's law. The calculation formula is:

[0070]

[0071] Where: α is the rock mass Boit constant, dimensionless; p s is the reservoir fluid pressure, MPa; ν is the rock mass Poisson’s ratio, dimensionless;

[0072] The in-situ principal stress of the hydrate reservoir is calculated according to the principle of stress superposition. That is, the in-situ principal stress field is equal to the sum of the gravity stress field and the tectonic stress field. So we have

[0073]

[0074] Where: k H , k h are the empirical tectonic stress coefficients in the directions of the maximum and minimum principal stresses at the reservoir level, dimensionless; σ x , σ y , σ z are the maximum and minimum horizontal principal stresses and vertical principal stresses of the reservoir, respectively, in MPa; n is the rock mass stress-strain characteristic index, dimensionless;

[0075] C. Calculate the intermediate constants f1, f2, and f4 based on Poisson's ratio, cohesion, internal friction angle, and rock mass Boit constant;

[0076]

[0077] Where: C is the cohesion of the rock mass, MPa; φ is the internal friction angle, °; α is the Boit constant of the rock mass, dimensionless; ν is the Poisson's ratio of the rock mass, dimensionless;

[0078] D. Calculate the coefficient f3 for any polar angle θ from θ = 0° to θ = 90° based on the in situ stress of the hydrate reservoir;

[0079] f3=(σ x +σ y )-2(σ x -σ y )cos(2θ) (8)

[0080] Where: x , σ y are the maximum and minimum principal stresses at reservoir level, respectively; θ is the polar angle, °;

[0081] E. Calculate the fracture pressure of three stress modes (first stress mode, second stress mode, third stress mode) of hydrate reservoir fracturing at any polar angle θ respectively;

[0082] The calculation formula of the rupture pressure of the first stress mode is:

[0083]

[0084] The calculation formula of the rupture pressure of the second stress mode is:

[0085]

[0086] The calculation formula of the rupture pressure of the third stress mode is:

[0087]

[0088] Where: are the fracture pressure of the first stress mode, the fracture pressure of the second stress mode, and the fracture pressure of the third stress mode respectively; α is the rock mass Boit constant, dimensionless; p s is the reservoir fluid pressure, MPa; σ v is the vertical principal stress of the hydrate reservoir, MPa;

[0089] F. Calculate the corresponding three-dimensional principal stresses using the fracture pressure under the three stress modes as the injection pressure;

[0090] F1. Calculate the radial and circumferential induced stresses caused by drilling on the wellbore wall based on the in-situ stress of the hydrate reservoir;

[0091] Considering that the hydrate reservoir is a homogeneous and isotropic material, an adjoining Figure 3 The cylindrical coordinate system shown has a polar radius of r and a polar angle (the angle with the direction of the maximum horizontal principal stress, i.e., the x-axis) of θ. The elastic mechanics notation is used: compressive stress is positive and tensile stress is negative. The radial and circumferential induced stresses of the borehole on the wall are calculated according to the elastic mechanics theory;

[0092] The calculation formula of radial and circumferential induced stress caused by drilling on the wellbore wall is:

[0093]

[0094] Where: r1 , σ θ1 are the stresses in radial and circumferential directions, MPa, respectively;

[0095] The radial and circumferential induced stresses generated by high-pressure injection of fluid into the wellbore during the fracturing process are calculated according to the infinite thick-walled cylinder formula;

[0096]

[0097] Where: r2 , σ θ2 are the radial and circumferential stresses generated by injecting fluid into the wellbore, MPa;

[0098] F2. Calculate the additional stress increment on the wellbore wall caused by stable seepage in the porous medium during the fracturing and injection process based on the rock mass Boit constant and the hydrate reservoir pore fluid pressure;

[0099] The fracturing process is considered as stable seepage of fracturing fluid into the reservoir. According to the research results of Haimson & Fairhurst, the additional stress increment at the wellbore wall caused by the change of seepage pore pressure can be calculated as follows:

[0100]

[0101] Where: r3 , σ θ3 are the radial and circumferential additional stress increments of the wellbore wall during stable seepage of fracturing injection fluid, MPa;

[0102] F3. Calculate the three principal stresses on the well wall based on the principle of stress superposition.

[0103] According to the principle of stress superposition, the total stress at a given point on the wellbore wall is obtained by superimposing the stress components on the wellbore wall.

[0104]

[0105] Where: r , σ θ , σ z They are the radial, circumferential and vertical stress components acting on the wellbore wall in the polar coordinate system, MPa.

[0106] G. Determine the hydrate reservoir fracturing stress mode based on the three-dimensional principal stresses, and check the corresponding stress mode. The result that is consistent with the stress mode and the response fracture pressure is taken as the true fracture pressure.

[0107] In hydraulic fracturing operations Figure 3 In the polar coordinate system shown, the radial stress is always greater than the circumferential stress. According to the relative magnitude relationship of the three principal stresses, it can be divided into the following three modes, namely

[0108] When σ r >σ z >σ θWhen , it is the first stress mode;

[0109] When σ z >σ r >σ θ When , it is the second stress mode;

[0110] When σ r >σ θ >σ z It is the third stress mode.

[0111] According to the nonlinear stress-strain characteristics of the hydrate reservoir rock mass, the Mohr-Columb strength criterion should be adopted, that is,

[0112] σ max =f1σ min +f2 (16)

[0113] Where: max , σ min are the maximum and minimum principal stresses, MPa, respectively.

[0114] During hydraulic fracturing operations, the three-dimensional effective principal stresses in the porous medium are:

[0115]

[0116] Where: r,e , σ θ,e are the effective total radial and total circumferential (tangential) stresses acting on the wellbore wall, MPa;

[0117] The fluid pressure when the formation breaks is the formation fracture pressure, that is, at this time, p F =p i The rupture pressure under different rupture modes is calculated based on the effective stress principle and the Mohr-Columb criterion shown in formula (16);

[0118] Example

[0119] A hydrate reservoir in the South China Sea has a water depth of 1200m and a rock layer thickness of 200m. According to well logging data, the average density of the overlying rock layer is 2400Kg / m 3 ; The empirical tectonic stress coefficients in the directions of maximum and minimum horizontal principal stresses in this area are 0.25 and 0.1, respectively.

[0120] The method of the present invention is used for prediction, which specifically comprises the following steps:

[0121] A. Core Experimental Test of Mechanical Properties of Hydrate Reservoir Rock Mass

[0122] A1. Drill the core of the hydrate reservoir and test the stress-strain curve of the hydrate reservoir in a material testing machine according to the national standard "Engineering Rock Test Method Standard" (GB / T50266-2013). Figure 1 According to the definition of Poisson's ratio, the rock Poisson's ratio is determined to be ν = 0.3763, and the stress-strain characteristic index n = 0.2037 is determined by regression method.

[0123] A2. Collect the cohesion of the hydrate reservoir C = 20 MPa and the internal friction angle The pore elastic constant α=0.7.

[0124] A3. Well logging data was used to determine that the pore fluid pressure of the hydrate reservoir was 8 MPa.

[0125] B. Calculate the in-situ stress of hydrate reservoir;

[0126] B1. Calculate the vertical principal stress of the hydrate reservoir using the density of the local overburden and the density of seawater. The density of seawater is 1025Kg / m according to experimental tests. 3 .

[0127]

[0128] B2. Calculate the horizontal component of gravity stress in hydrate reservoir;

[0129] According to Terzaghi effective stress theory and based on the rock mass stress-strain model obtained in step A1, the horizontal component of the in-situ gravity stress of the hydrate reservoir is calculated according to the generalized Hook's law;

[0130]

[0131] B3. Calculate the in-situ three-dimensional principal stresses of the hydrate reservoir;

[0132] The in-situ principal stress of the target reservoir is calculated according to the principle of stress superposition. That is, the in-situ stress field is equal to the sum of the gravity stress field and the tectonic stress field. So we have

[0133]

[0134] C. Calculate the intermediate constants f1, f2, and f4 based on Poisson's ratio, cohesion, internal friction angle, and rock mass Boit constant;

[0135]

[0136] D. Calculate the coefficient f3 for any polar angle θ from θ = 0° to θ = 90° based on the in situ stress of the hydrate reservoir;

[0137] f3=(σ x +σ y )-2(σx -σ y )cos(2θ)=28.338-5.028cos(2θ)

[0138] The following calculations take the polar angle θ = 0° as an example.

[0139] f3=(σ x +σ y )-2(σ x -σ y )cos(2θ)=28.338-5.028cos(0)=23.31

[0140] E. Calculate the fracture pressure of three stress modes of hydrate reservoir fracturing at any polar angle θ respectively;

[0141] The fracture pressure calculation model of hydrate reservoir vertical wells under different fracturing modes is established by the following steps:

[0142] 1. Select and determine the criterion for hydrate reservoir fracture strength.

[0143] According to the nonlinear stress-strain characteristics of hydrate reservoirs, the Mohr-Columb strength criterion is adopted;

[0144] 2. Three-dimensional effective stress calculation model for hydrate reservoirs.

[0145] During hydraulic fracturing operations, the three-dimensional effective principal stresses in the porous medium are:

[0146]

[0147] 3. Calculation methods of burst pressure under three stress modes

[0148] According to the effective stress principle and the Mohr-Columb criterion shown in formula (16), the rupture pressure under different rupture modes is calculated. At this time, p F =p i .

[0149] 1) First stress mode: σ max =σ r,e σ min =σ θ,e , the burst pressure is:

[0150]

[0151] 2) Second stress mode: σ min =σ θ,e σ max =σ z,e , the formation fracture pressure is:

[0152]

[0153] 3) The third stress mode: σ min =σ z,e σ max =σ r,e , the formation fracture pressure is:

[0154]

[0155] 4) Programming to calculate the rupture pressure of three rupture modes at different polar angles. The calculation results are shown in the attached Figure 4 The minimum value is obtained when the polar angle θ = 0°, that is, the corresponding rupture pressure is {21.58 22.95 35.38}.

[0156] F. Determine the fracture pressure value of the hydrate reservoir;

[0157] The corresponding three-dimensional principal stresses calculated using the fracture pressure {21.58 22.95 35.38} in the three modes as the injection pressure are shown in Table 1.

[0158] G. Calculate the stress induced by the borehole stress and the stress induced by the injection of fluid into the wellbore;

[0159] Considering that the hydrate reservoir is a homogeneous and isotropic material, the attached Figure 3 In the cylindrical coordinate system shown, compressive stress is positive and tensile stress is negative.

[0160] G1. Calculate the radial and circumferential induced stresses caused by the wellbore on the wellbore wall;

[0161]

[0162] G2. The radial and circumferential induced stresses generated by high pressure injection into the wellbore during fracturing are calculated according to the infinite thick-walled cylinder formula.

[0163]

[0164] H. Calculate the additional stress increment on the wellbore wall caused by stable seepage in the porous medium during the fracturing and injection process;

[0165] The percolation of fracturing fluid into the reservoir during the fracturing process is regarded as stable seepage, and the induced stress on the well wall caused by the change of seepage pore pressure can be calculated as follows:

[0166]

[0167] I. Superimpose and calculate the total three-dimensional stress on the wellbore wall to identify the fracturing mode of the hydrate reservoir;

[0168] I1. According to the principle of stress superposition, the stress components on the wellbore wall are superimposed to obtain the total stress on the wellbore wall;

[0169]

[0170] I2. Method for identifying hydrate reservoir fracturing patterns.

[0171] In hydraulic fracturing operations Figure 3 In the polar coordinate system shown, the radial stress is always greater than the circumferential stress. According to the relative magnitude relationship of the three principal stresses, it can be divided into the following three modes, namely

[0172] First stress mode: σ r >σ z >σ θ

[0173] Second stress mode: σ z >σ r >σ θ

[0174] The third stress mode: σ r >σ θ >σ z

[0175] Table 1

[0176]

[0177]

[0178] J. The result when the stress pattern is consistent with the corresponding fracture pressure is the true fracture pressure.

[0179] The injection pressures {21.58, 22.95, 35.38} are all used to check the first stress mode, and the actual fracture pressure of the hydrate reservoir is obtained to be 21.58 MPa.

[0180] The above description is not intended to limit the present invention in any form. Although the present invention has been disclosed through the above embodiments, it is not intended to limit the present invention. Any technician familiar with the profession can make some changes or modifications to equivalent embodiments of equivalent changes using the technical contents disclosed above without departing from the scope of the technical solution of the present invention. However, any simple modification, equivalent changes and modifications made to the above embodiments based on the technical essence of the present invention without departing from the content of the technical solution of the present invention are within the scope of the technical solution of the present invention.

Claims

1. A calculation method for predicting the hydraulic fracturing pressure of a vertical well in a hydrate reservoir, characterized in that: The following steps are involved: A. Collect the stress-strain characteristic coefficient, stress-strain characteristic index, Poisson's ratio, cohesion, internal friction angle, rock mass Boit constant and pore fluid pressure of the hydrate reservoir; B. Calculate the in-situ stress of the hydrate reservoir based on the strain characteristic index, Poisson's ratio, rock mass Boit constant and pore fluid pressure of the hydrate reservoir; C. Calculate the intermediate constants f1, f2, and f4 based on Poisson's ratio, cohesion, internal friction angle, and rock mass Boit constant; D. Calculate the coefficient f3 for any polar angle θ from θ = 0° to θ = 90° based on the in situ stress of the hydrate reservoir; E. Calculate the fracture pressure of three stress modes of hydrate reservoir fracturing at any polar angle θ respectively; F. Calculate the corresponding three-dimensional principal stresses using the fracture pressure under the three stress modes as the injection pressure; G. Determine the hydrate reservoir fracturing stress mode based on the three-dimensional principal stresses, and check the corresponding stress mode. The result that is consistent with the stress mode and the response fracture pressure is taken as the true fracture pressure.

2. The method for calculating the fracture pressure of a vertical well hydraulic fracturing in a hydrate reservoir according to claim 1, characterized in that: The calculation formula in step B is: Where: k H , k h are the empirical tectonic stress coefficients in the directions of the maximum and minimum principal stresses in the reservoir, dimensionless; α is the Boit constant of the rock mass, dimensionless; p s is the reservoir fluid pressure, MPa; ν is the rock mass Poisson’s ratio, dimensionless; dz is the integral variable, m; L water , L goal is the seawater depth and target reservoir depth, m; ρ water , rock are the density of seawater and local overburden strata that vary with depth, Kg / m 3 ; σ v is the vertical principal stress of the hydrate reservoir, MPa; g is the gravitational acceleration, m / s 2 ; σ h is the horizontal component of the in-situ gravity stress of the hydrate reservoir, MPa; σ x , σ y , σ z are the maximum and minimum horizontal principal stresses and vertical principal stress of the reservoir, respectively, in MPa; n is the rock mass stress-strain characteristic index, dimensionless.

3. The method for calculating the fracture pressure of a vertical well hydraulic fracturing in a hydrate reservoir according to claim 1, characterized in that: The calculation formula in step C is: Where: C is the cohesion of the rock mass, MPa; φ is the internal friction angle, °; α is the Boit constant of the rock mass, dimensionless; ν is the Poisson's ratio of the rock mass, dimensionless.

4. The method for calculating the fracture pressure of a vertical well hydraulic fracturing in a hydrate reservoir according to claim 1, characterized in that: The calculation formula in step D is: f3=(σ x +s y )-2(p x -s y )cos(2θ) Where: x , σ y are the maximum and minimum principal stresses at reservoir level, respectively; θ is the polar angle, °.

5. The method for calculating the fracture pressure of a vertical well hydraulic fracturing in a hydrate reservoir according to claim 1, characterized in that: The three stress modes of hydrate reservoir fracturing in step E include a first stress mode, a second stress mode, and a third stress mode; The calculation formula of the rupture pressure of the first stress mode is: The calculation formula of the rupture pressure of the second stress mode is: The calculation formula of the rupture pressure of the third stress mode is: Where: are the fracture pressure of the first stress mode, the fracture pressure of the second stress mode, and the fracture pressure of the third stress mode respectively; α is the rock mass Boit constant, dimensionless; p s is the reservoir fluid pressure, MPa; σ v is the vertical principal stress of the hydrate reservoir, MPa.

6. The method for calculating the fracture pressure of a vertical well hydraulic fracturing in a hydrate reservoir according to claim 1, characterized in that: The specific calculation process of the three principal stresses in step F is: F1. Calculate the radial and circumferential induced stresses caused by drilling on the wellbore wall based on the in-situ stress of the hydrate reservoir; F2. Calculate the additional stress increment on the wellbore wall caused by stable seepage in the porous medium during the fracturing and injection process based on the rock mass Boit constant and the hydrate reservoir pore fluid pressure; F3. Calculate the three principal stresses on the well wall based on the principle of stress superposition.

7. A calculation method for predicting hydraulic fracturing pressure of a vertical well in a hydrate reservoir according to claim 6, characterized in that: The calculation formula in step F1 is: Where: r2 , σ θ2 are the radial and circumferential stresses generated by fluid injection into the wellbore, MPa; σ r1 , σ θ1 are the stresses in radial and circumferential directions, MPa; p i is the injection pressure into the wellbore, MPa.

8. The method for calculating the fracture pressure of a vertical well hydraulic fracturing in a hydrate reservoir according to claim 6, characterized in that: The calculation formula in step F2 is: Where: r3 , σ θ3 are the radial and circumferential additional stress increments of the wellbore during stable seepage of fracturing injection fluid, MPa; p i is the injection pressure into the wellbore, MPa; p s is the pore fluid pressure in the reservoir, MPa.

9. A calculation method for predicting hydraulic fracturing pressure of a vertical well in a hydrate reservoir according to claim 6, characterized in that: The calculation formula in step F3 is: Where: r , σ θ , σ z are the radial, circumferential and vertical stress components acting on the wellbore wall in the polar coordinate system, MPa; p i is the injection pressure into the wellbore, MPa.

10. The method for calculating the fracture pressure of a vertical well hydraulic fracturing in a hydrate reservoir according to claim 1, characterized in that: The specific judgment criteria for determining the hydrate reservoir fracturing stress mode based on the three-dimensional principal stress in step G are: When σ r >σ z >σ θ When , it is the first stress mode; When σ z >σ r >σ θ When , it is the second stress mode; When σ r >σ θ >σ z It is the third stress mode.

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