Method for determining the maximum horizontal principal stress by well logging

Abstract

The method for determining the maximum horizontal principal stress by logging belongs to the field of logging technology and includes the following steps: (1) obtaining parameter data related to the maximum horizontal principal stress according to the logging data, the parameters including: mud content, porosity, Poisson's ratio, Young's modulus and minimum horizontal principal stress; (2) obtaining the orthogonal dipole fast shear wave velocity and the orthogonal dipole slow shear wave velocity according to orthogonal dipole shear wave logging or simulated orthogonal dipole shear wave logging; (3) obtaining the logging curve value according to the preset depth step length based on the obtained parameter data related to the maximum horizontal principal stress, the orthogonal dipole fast shear wave velocity and the orthogonal dipole slow shear wave velocity, and calculating one or more sections of the maximum horizontal principal stress of the measuring well section. The present invention solves the problem that the maximum horizontal principal stress is not easy to obtain accurately, and is applicable to conventional oil and gas reservoirs, as well as to unconventional oil and gas reservoirs such as tight sandstone, shale, carbonate rock, etc. It has a wide range of applications and high calculation accuracy.

Description

Technical Field

[0001] The invention belongs to the technical field of well logging and relates to a method for determining horizontal maximum principal stress through well logging. Background Art

[0002] Geostress includes vertical principal stress, horizontal maximum principal stress and horizontal minimum principal stress. The horizontal geostress profile can reflect the longitudinal variation of the geostress field. Accurately obtaining horizontal geostress parameters can provide basic parameters for decision-making and design in various links such as drilling engineering, oil and gas reservoir engineering and oil and gas production engineering. Therefore, obtaining horizontal geostress profiles is of great significance for the development of oil and gas fields.

[0003] Among the three-dimensional geostress parameters, the vertical principal stress is calculated by accumulating the volume density logging values. If there is a density curve in the logging data, this parameter is easier to obtain. At present, the method for obtaining the horizontal minimum principal stress is relatively complete. According to different formation lithology, different porosity, and different permeability, the Anderson, Techahi, Newmeyer, combined spring and other models can be used to calculate the horizontal minimum principal stress.

[0004] It is still difficult to obtain the maximum horizontal principal stress. At present, there are three main methods: core laboratory test, logging data calculation and field measurement. Core test is affected by many factors, and the test cost is high and the data is limited. The cost of ground field measurement is high, and not all strata can be measured by this method, and continuous ground stress profiles cannot be obtained. Well logging data can reflect the changing characteristics of the mechanical properties of rocks with the depth of the stratum. It is convenient, simple, low-cost to calculate the ground stress parameters, and continuous ground stress profiles can be obtained. Summary of the invention

[0005] The purpose of the present invention is to provide a method for determining the maximum horizontal principal stress by logging. There are three main parameters that affect the maximum horizontal principal stress: Young's modulus, Poisson's ratio and fast and slow shear wave velocities of the formation, from which the horizontal stress difference can be obtained. The Young's modulus and Poisson's ratio of the formation can be obtained using the longitudinal and shear wave time difference and the volume density, and the fast and slow shear wave velocities are obtained by orthogonal dipole shear wave logging. When there is no orthogonal dipole shear wave logging data, the horizontal pressure difference can be calculated by simulating the orthogonal dipole fast and slow shear waves, and the horizontal pressure difference can be obtained, and then the horizontal maximum principal stress can be obtained. The method of calculating the horizontal maximum principal stress using logging data of the present invention is fast, simple, accurate, and highly practical, and can be well used in oil and gas exploration and development. The specific technical scheme is as follows.

[0006] The method for determining the maximum horizontal principal stress by well logging is characterized by comprising the following steps:

[0007] (1) Obtaining parameter data related to the maximum horizontal principal stress based on the well logging data, the parameters including: shale content, porosity, Poisson's ratio, Young's modulus and minimum horizontal principal stress;

[0008] (2) Obtaining the orthogonal dipole fast shear wave velocity and the orthogonal dipole slow shear wave velocity based on orthogonal dipole shear wave logging or simulated orthogonal dipole shear wave logging;

[0009] (3) Based on the acquired parameter data related to the horizontal maximum principal stress, the orthogonal dipole fast shear wave velocity, and the orthogonal dipole slow shear wave velocity, the logging curve value is obtained according to the preset depth step, and the horizontal maximum principal stress of one or more sections of the measuring well section is calculated.

[0010] Furthermore, the porosity POR is calculated by the volume density, compensated neutron and P-wave time difference in the logging data. The calculation formula is as follows:

[0011] POR = (AC - TM) / (CP×(TF - TM)) –SH×(TSH - TM) / (TF - TM)

[0012] Where: AC represents the logging value of the longitudinal wave time difference curve, in μs / ft; TM represents the logging value of the skeleton time difference, in μs / ft; TF represents the logging value of the fluid time difference, in μs / ft; SH represents the mud content, which is dimensionless; TSH represents the logging value of the mudstone time difference, in μs / ft; CP represents the formation compaction correction coefficient, which is dimensionless.

[0013] Furthermore, the shale content SH is calculated by the natural gamma, natural potential and compensated neutron data in the well logging data. The calculation formula is as follows:

[0014] sh1=(value-shsa) / (shale-shsa)

[0015] SH= (pow(2.0,(GCUR× sh1)) -1.0) / (pow(2.0,GCUR)-1.0)

[0016] Wherein: sh1 represents the relative value of the logging curve for calculating the shale content, value represents the logging values ​​of several curves (which can represent the value of natural gamma, natural potential or compensated neutron curve), shsa represents the logging value of sandstone, shale represents the logging value of mudstone; SH represents the shale content and is dimensionless; the function pow(x, y) represents the calculation of x to the power of y, and GCUR represents the formation identifier: 3.7 for new formations and 2 for old formations.

[0017] Furthermore, the Poisson's ratio POIS is calculated using the longitudinal wave data and shear wave data in the logging data. The calculation formula is as follows:

[0018] POIS = (0.5×TS×TS-AC×AC) / (TS×TS-AC×AC)

[0019] Where: TS represents the shear wave time difference, unit is μs / ft; AC represents the longitudinal wave time difference, unit is μs / ft.

[0020] Furthermore, the Young's modulus YMOD is calculated by the longitudinal wave data, shear wave data, and volume density data in the logging data. The calculation formula is as follows:

[0021] NUM = 3.0×TS×TS-4.0×AC×AC

[0022] BOTM = TS×TS-AC×AC

[0023] YMOD = 9238.0×DEN×NUM / (TS×TS×BOTM)

[0024] Where: YMOD represents Young's modulus, unit MPa; NUM and BOTM are intermediate variables; TS represents transverse wave time difference, unit μs / ft; AC represents longitudinal wave time difference, unit μs / ft; DEN represents volume density, unit g / cm 3 .

[0025] Furthermore, the calculation formula of the horizontal maximum principal stress is as follows:

[0026] PORX = POR × (1.0-SH)

[0027] DXY = 0.2151 × PORX

[0028] DDXY = DXY + 0.008×YMOD – 0.05×POIS

[0029] SDX = SDY + DDXY

[0030] Where: PORX represents the porosity correction value, dimensionless; SH represents the shale content, dimensionless; POR represents the porosity, dimensionless; DXY represents the intermediate variable of the horizontal principal stress difference, unit MPa; 0.2151 represents the regression coefficient, that is, the regression coefficient of the horizontal geostress difference and porosity is obtained by fitting the orthogonal dipole fast shear wave and the orthogonal dipole slow shear wave of the existing wells with the porosity; YMOD represents Young's modulus, unit 10 4 MPa; POIS represents Poisson’s ratio, dimensionless; DDXY represents horizontal stress difference, unit is MPa; SDX represents horizontal maximum principal stress, unit is MPa; SDY represents horizontal minimum principal stress, unit is MPa.

[0031] Compared with the prior art, the present invention has the following beneficial effects. The method for determining the maximum horizontal principal stress by logging provided by the present invention utilizes the principle that the greater the difference between the fast shear wave velocity and the slow shear wave velocity in dipole shear wave logging, the greater the horizontal stress difference; and when there is no dipole shear wave logging curve, the dipole shear wave logging principle can be simulated to obtain the horizontal stress difference; at the same time, since the horizontal stress difference is affected by the size of Young's modulus and Poisson's ratio, that is, the larger the Young's modulus, the smaller the Poisson's ratio, and the greater the horizontal stress difference. In this way, by using these three parameters for comprehensive calculation, a more satisfactory horizontal principal stress difference can be obtained, and then the correct horizontal maximum principal stress can be obtained. With the correct three stresses, the problem of obtaining the correct formation fracture pressure and collapse pressure can be solved. This method is applicable to both conventional oil and gas reservoirs and unconventional oil and gas reservoirs such as tight sandstone, shale, carbonate rock, coal seam, etc. It has a wide range of applications and high calculation accuracy. BRIEF DESCRIPTION OF THE DRAWINGS

[0032] Figure 1 It is a schematic diagram of the calculation process of the method for determining the maximum horizontal principal stress through well logging of the present invention.

[0033] Figure 2 This is a diagram of the calculation results of the geostress in Example 1.

[0034] In the figure: GR represents natural gamma, in API; AC represents longitudinal wave time difference, in μs / ft; SDX represents horizontal maximum principal stress, in MPa; SDY represents horizontal minimum principal stress, in MPa; SDXL represents the average value of horizontal maximum principal stress, in MPa; SDYL represents the average value of horizontal minimum principal stress, in MPa; SH represents mud content, dimensionless; POR represents porosity, dimensionless. DETAILED DESCRIPTION

[0035] The technical solution of the present invention is described clearly and completely below in conjunction with the accompanying drawings of the specification. Obviously, the described implementation is only a part of the implementation of the present invention, not all of the implementations. Based on the implementation of the present invention, all other implementations obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0036] Figure 1 A schematic diagram of the calculation process of the method for determining the horizontal maximum principal stress through well logging provided by the present invention.

[0037] The specific steps of the present invention include:

[0038] 1) Read the value of the logging curve continuously according to the measurement section of the logging curve and a certain depth step, and the step length shall not exceed 1 meter; the measurement section is divided into one or more sections to select the calculation parameters.

[0039] 2) Obtain the shale content of the formation through natural gamma or natural potential or compensated neutron in logging data and the newness and age of the formation.

[0040] 3) Obtain porosity through the P-wave time difference or volume density or compensated neutron and formation compaction correction coefficient in the logging data.

[0041] 4) Obtain Poisson's ratio through logging data.

[0042] 5) Obtain Young’s modulus through logging data.

[0043] 6) Calculate the horizontal stress difference DXY by using the fast and slow shear wave velocities in the orthogonal dipole shear wave logging data or by simulating the orthogonal dipole shear wave logging principle.

[0044] 7) Calculate the horizontal stress difference using the formula DDXY = DXY + 0.008×YMOD – 0.05×POIS.

[0045] 8) Calculate the maximum horizontal principal stress using the formula SDX = SDY + DDXY.

[0046] 9) Output SDX calculation results according to user needs to guide oil and gas field exploration and development or reservoir fracturing and water injection development work.

[0047] The method of the present invention is described in more detail below with reference to specific embodiments.

[0048] Example 1

[0049] The method of the present invention is applied to the carbonate well YB27-3H, which specifically includes the following steps:

[0050] Step A1: Calculate based on the measured well section values. The target layer section of YB27-3H well is 6570-7606 meters, the perforation section is 6765.5-6782.5 meters, and the logging interpretation porosity is 5.8%, which belongs to carbonate reservoir.

[0051] Step A2: Obtain the formation mud content. According to the data provided by the well logging interpretation, the mud content of this reservoir is 1.25%;

[0052] Step A3: Obtain Poisson's ratio. According to the measured longitudinal wave and calculated shear wave of the perforated well section, the Poisson's ratio of the well section is obtained to be 0.3;

[0053] The Young's modulus was obtained. Based on the measured longitudinal waves and calculated shear waves and volume density of the perforated well section, the Young's modulus YMOD was further obtained to be 6.86;

[0054] To obtain the minimum horizontal principal stress, the formation is deep and dense, and the Newberry model is used for calculation; the average value of the minimum horizontal principal stress sdYL of this reservoir is 140.5MPa;

[0055] Step A4: Obtain the maximum horizontal principal stress, simulate the principle of orthogonal dipole shear wave logging to calculate the horizontal stress difference and combine it with Young's modulus and Poisson's ratio to comprehensively calculate the reservoir stress difference of 62MPa, add it to the minimum horizontal principal stress to obtain the average value of the maximum horizontal principal stress sdxL of 202.5MPa;

[0056] The calculation formula is as follows:

[0057] PORX=POR×(1.0-SH)

[0058] DXY=0.2151×PORX,

[0059] DDXY = DXY + 0.008×YMOD – 0.05×POIS,

[0060] SDX = SDY + DDXY,

[0061] SDX = 202.5 MPa;

[0062] Step A5: Output the calculation results of the horizontal maximum principal stress SDX according to user requirements.

[0063] The method in this embodiment is used to calculate the average value SDXL of the maximum horizontal principal stress in the perforated layer section of the horizontal well YB27-3H at 6765.5-6782.5 meters, which is 202.5 MPa. After the well is completed, researchers of oilfield engineering geological characteristics use a combined spring geostress calculation model to obtain the maximum horizontal principal stress of this section as 208.5 MPa.

[0064] The error between the maximum horizontal principal stress of the reservoir calculated in this embodiment and the maximum horizontal principal stress calculated by the on-site geological engineering personnel is about 3%, and the two are basically consistent, which meets the actual construction needs on site and has high application value.

[0065] Example 2

[0066] The method of the present invention is applied in the ZH29 well in the sandstone-mudstone formation, and specifically comprises the following steps:

[0067] Step A1: Calculate based on the measured well section values. The target layer section of Well ZH29 is 3754.5-3771 meters, the perforated well section is 3761.8-3771 meters, and the logging interpretation porosity is 16%, which belongs to the sandstone-mudstone reservoir;

[0068] Step A2: Obtain the formation mud content. According to the data provided by the well logging interpretation, the reservoir mud content is 7.0%;

[0069] Step A3: Obtain Poisson's ratio. According to the measured longitudinal waves and calculated shear waves of the perforated well section, the Poisson's ratio of the well section is obtained to be 0.25.

[0070] The Young's modulus was obtained. Based on the measured longitudinal waves and calculated shear waves and volume density of the perforated well section, the Young's modulus YMOD was further obtained to be 3.1;

[0071] To obtain the minimum horizontal principal stress, the formation is deep but not dense, so the Anderson model is used for calculation. The average value of the minimum horizontal principal stress SDYL of this reservoir is 51.5MPa.

[0072] Step A4: Obtain the maximum horizontal principal stress, simulate the principle of orthogonal dipole shear wave logging to calculate the horizontal stress difference and combine it with Young's modulus and Poisson's ratio to comprehensively calculate the reservoir stress difference of 10.5MPa, add it to the minimum horizontal principal stress to obtain the average value of the maximum horizontal principal stress SDXL of 62.0MPa;

[0073] The calculation formula is as follows:

[0074] PORX=POR×(1.0-SH)

[0075] DXY=0.2151×PORX,

[0076] DDXY = DXY + 0.008×YMOD – 0.05×POIS,

[0077] SDX = SDY + DDXY,

[0078] SDX = 62.0 MPa;

[0079] Step A5: Output the calculation results of the horizontal maximum principal stress SDX according to user requirements.

[0080] The method in this embodiment is used to calculate the average value SDXL of the maximum horizontal principal stress of the perforated layer section 3761.8-3771.0 meters of the vertical well ZH29, which is 62.0 MPa; after the well is completed, the oilfield engineering geology researchers obtain the maximum horizontal principal stress of the well section as 63.0 MPa on site.

[0081] The error between the maximum horizontal principal stress of the reservoir calculated in this embodiment and the maximum horizontal principal stress obtained by the on-site geological engineering personnel is about 1.6%. The two are basically consistent, meet the actual construction needs on site, and have high application value.

[0082] Although the embodiments of the present invention have been shown and described above, it is understood that the above embodiments are exemplary and cannot be understood as limiting the present invention. A person skilled in the art may change, modify, replace and modify the above embodiments within the scope of the present invention without departing from the principles and purpose of the present invention. The protection scope of the present invention is defined by the claims and their equivalent technical solutions.

Claims

1. A method for determining the maximum horizontal principal stress by well logging, characterized in that: The following steps are involved: (1) Obtaining parameter data related to the maximum horizontal principal stress based on well logging data, the parameters including: shale content, porosity, Poisson's ratio, Young's modulus and minimum horizontal principal stress; The shale content SH is calculated by the curve natural gamma, natural potential, and compensated neutron data in the logging data. The calculation formula is as follows: sh1=(value-shsa) / (shale-shsa) SH= (pow(2.0,(GCUR× sh1)) -1.0) / (pow(2.0,GCUR)-1.0) Where: sh1 represents the relative value of the logging curve for calculating the shale content, value represents the logging value of the curve, shsa represents the logging value of sandstone, and shale represents the logging value of mudstone; the function pow(x, y) represents the calculation of x to the power of y, and GCUR represents the formation identifier: 3.7 for new formations and 2 for old formations; The porosity POR is calculated by volume density, compensated neutron and P-wave time difference in the logging data. The calculation formula is as follows: POR = (AC - TM) / (CP×(TF - TM)) –SH×(TSH - TM) / (TF - TM) Where: AC is the logging value of the longitudinal wave time difference curve, unit μs / ft; TM is the logging value of the skeleton time difference, unit μs / ft; TF is the logging value of the fluid time difference, unit μs / ft; SH is the shale content, dimensionless; TSH is the logging value of the mudstone time difference, unit μs / ft; CP is the formation compaction correction coefficient, dimensionless; The Poisson's ratio POIS is calculated using the longitudinal wave data and shear wave data in the logging data. The calculation formula is as follows: POIS = (0.5×TS×TS-AC×AC) / (TS×TS-AC×AC) Where: TS represents the shear wave time difference, unit is μs / ft; The Young's modulus YMOD is calculated using the longitudinal wave data, shear wave data, and volume density data in the well logging data. The calculation formula is as follows: NUM = 3.0×TS×TS-4.0×AC×AC BOTM = TS×TS-AC×AC YMOD = 9238.0×DEN×NUM / (TS×TS×BOTM) Where: YMOD represents Young's modulus, unit: MPa; NUM and BOTM are intermediate variables; DEN represents volume density, unit: g / cm 3 ; (2) Obtaining the orthogonal dipole fast shear wave velocity and the orthogonal dipole slow shear wave velocity based on orthogonal dipole shear wave logging or simulated orthogonal dipole shear wave logging; (3) Based on the obtained parameter data related to the maximum horizontal principal stress, the orthogonal dipole fast shear wave velocity and the orthogonal dipole slow shear wave velocity, the well logging curve value is obtained according to the preset depth step, and the maximum horizontal principal stress of one or more sections of the measuring well section is calculated; the calculation formula of the maximum horizontal principal stress is as follows: PORX = POR × (1.0-SH) DXY = 0.2151 × PORX DDXY = DXY + 0.008×YMOD – 0.05×POIS SDX = SDY + DDXY Wherein: PORX represents the porosity correction value, dimensionless; POR represents the porosity, dimensionless; DXY represents the intermediate variable of the horizontal maximum principal stress; POIS represents the Poisson's ratio, dimensionless; DDXY represents the horizontal stress difference, unit MPa, SDX represents the horizontal maximum principal stress, unit MPa; SDY represents the horizontal minimum principal stress, unit MPa.

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