CN117826251A - Shale oil reservoir rock physical modeling method based on logging data inversion pore parameters - Google Patents

Abstract

The invention discloses a shale oil reservoir rock physical modeling method based on logging data inversion pore parameters, which comprises the following steps: 1) Obtaining the density, the porosity, the XRD mineral content and the broadband ultrasonic longitudinal and transverse wave speed of a laboratory test core sample through experimental tests; 2) Selecting equivalent medium models respectively suitable for the rock salt and the intersalic shale stratum according to the simulation data; 3) Extracting the speed and pressure relations of different lithology rocks in a well to obtain a fitting relation between the bulk modulus of the dry rock and the full-range pressure; 4) Lithology is adopted to construct a dry rock model with multiple pore parameters; 5) And constructing a fluid displacement model by adopting a mode of rock salt and interlayer lithology modeling. Aiming at the characteristics of unique geological geophysics of the rock salt and the inter-salt stratum, the method forms a set of speed dispersion petrophysical modeling method which considers the influence of multiple pore structures and fluid under the variable pressure condition of the inter-salt shale oil stratum.

Description

Shale oil reservoir rock physical modeling method based on logging data inversion pore parameters

Technical Field

The invention relates to petrophysical and hydrocarbon geophysical technologies, in particular to a shale oil reservoir petrophysical modeling method based on inversion of pore parameters of logging data.

Background

Shale oil is used as an important petroleum successor energy in the future in China, and the relation between reservoir physical properties and elastic characteristics is complex, so that the shale oil is a current geophysical exploration difficulty. There is a need for a petrophysical modeling method suitable for shale oil formation characteristics that addresses the practical reservoir prediction problem. The invention takes Jiang Han basin salt-to-salt shale oil stratum as a research object, the stratum is a unique land salt lake sediment in China, and is a multi-rhythm stratum formed by interaction of rock salt and salt-to-salt shale, and has the characteristics of rapid lithology change, complex structure and pore structure and the like. Currently, although there are a variety of petrophysical modeling methods that consider complex model parameters, such as Xu-White model, xu-Pane model, and anisotropic shale model, these models are limited to sandstone, carbonate, and shale reservoirs. The high-pressure modulus of the dry rock can be used by students at home and abroad to obtain multiple pore structure parameters (parameters such as hard porosity, soft porosity and the like). However, there is no modeling method that considers multiple pore structure parameters that can be applied to actual shale oil formations, because petrophysical models have difficulty in obtaining them when solving practical problems, and are generally limited to artificially given single pore structure parameters such as pore aspect ratio α, which makes it difficult to efficiently characterize the elastic properties of shale reservoirs with complex pore structures.

Disclosure of Invention

Aiming at the defects in the prior art, the invention provides a shale oil reservoir rock physical modeling method for inverting pore parameters based on logging data.

The technical scheme adopted for solving the technical problems is as follows: a shale oil reservoir rock physical modeling method based on logging data inversion pore parameters comprises the following steps:

1) Obtaining the density, the porosity, the XRD mineral content and the broadband ultrasonic longitudinal and transverse wave speed of a core sample through testing; determining stratum physical properties and elasticity characteristics by combining the target interval data of the comparison logging;

2) Based on core test data, fitting an ultrasonic test speed-pressure relation to obtain an extremely high pressure speed, and simulating soft porosity phi at each pressure point in the depressurization process through model inversion _c And aperture aspect ratio alpha _c The method comprises the steps of carrying out a first treatment on the surface of the According to the simulation data, selecting equivalent medium models respectively suitable for the rock salt and the intersalic shale stratum;

3) Extracting rock velocity and pressure relations of different lithology in a well;

3.1 Extracting depth and acoustic logging speed data points of different wells and different lithologies in the same stratum according to the well connecting profile, converting the depth value into a pressure value through a pressure gradient, converting the logging acoustic speed into a saturated rock bulk modulus in combination with logging density, and fitting the data points of the pressure-bulk modulus to obtain a relation formula of full-range pressure and the saturated bulk modulus:

wherein: f (F) _fit To fit a function, P _well To extract pressure points in the well, K _well The saturated bulk modulus calculated for the extracted sonic velocity in the well,the saturated rock bulk modulus under any pressure under the same lithology is obtained by fitting;

3.2 Based on a)As a result of fluid replacement, the relation of the change of the dry rock bulk modulus with the pressure is obtained:

wherein:is the bulk modulus of dry rock at any pressure at the same lithology; phi is the porosity of the well log, K _f For bulk modulus of fluid, K _m Is the bulk modulus of the matrix;

the fitting relation between the bulk modulus of the dry rock and the full-range pressure can be obtained;

4) Calculating the aspect ratio of hard pores, the micro-crack porosity and the micro-crack aspect ratio by using experimental test data and logging data, and constructing a dry rock model with multiple pore parameters according to lithology;

the method comprises the following steps:

4.1 According to the relation between the dry rock bulk modulus and the pressure obtained in the step 3), establishing an objective function through an equivalent medium theoretical model simulation result and the dry rock bulk modulus under different pressures, and inverting to obtain the aspect ratio alpha of a single hard pore in the well _s Aspect ratio parameter alpha of multiple microcrack _c And a corresponding soft porosity phi _c (α _c ) Distribution;

4.2 Taking logging data (mineral content, porosity and saturation) and inversion parameters (corresponding to different depth point data in a well) obtained in the step 4) as inputs, respectively taking the logging data into the equivalent medium model determined in the step 2), and obtaining the dry rock skeleton modulus of each depth point of the shale stratum between salt rocks and salt;

5) Constructing a fluid displacement model by adopting a mode of rock salt and interlayer lithology modeling;

bulk modulus K of rock at full saturation at arbitrary pressure _Saturation And shear modulus G _Saturation The expression as a function of frequency is:

wherein,is the bulk modulus of the rock matrix, replaced by the bulk modulus of the dry rock fitted at any pressure; phi (phi) _c (p) represents the total porosity of the microcrack at an effective pressure; note here that α for computational convenience _c The soft pore aspect ratio corresponding to the maximum of the porosity in the microcrack aspect ratio distribution. η is the pore fluid viscosity coefficient and ω is the circular frequency.And->Represents the bulk modulus and the shear modulus of the dry rock framework under certain pressure of the rock salt and the shale between the salt,to fit the bulk modulus of extremely high pressure dry rock in the well.

According to the above scheme, in the step 2), the equivalent medium models of the rock salt and the shale stratum between the rock salt are respectively an SCA model and a DEM model.

According to the scheme, the micro-crack porosity phi _c And microcrack aspect ratio alpha _c The acquisition process is as follows:

acquiring the crack density of the rock according to an equivalent medium model of the rock and the intersalt shale stratum, calculating the cumulative crack density of the rock, and finally respectively calculating and obtaining the micro-crack aspect ratio distribution alpha of the rock and the intersalt shale stratum under any pressure by the cumulative crack density of the rock and the intersalt shale stratum, the fitting high-pressure volume modulus in a well and the volume modulus under any pressure _c And micro-crack porosity phi _i 。

The invention has the beneficial effects that:

aiming at the characteristics of unique geological geophysics of salt rocks and formations between salts, the method provided by the invention specifically develops petrophysical experiment tests, builds the change rule of the bulk modulus of dry rock with different lithologies along with pressure by combining logging data, considers the multiple pore parameter distribution and the dispersion problem caused by pore fluid flow to carry out petrophysical modeling, and finally forms a set of velocity dispersion petrophysical modeling method aiming at the multiple pore structure and fluid influence under the variable pressure condition of the shale oil formations between salts. The method plays a certain guiding role in reservoir prediction of shale oil stratum including logging interpretation, seismic inversion, dessert identification and the like.

Drawings

The invention will be further described with reference to the accompanying drawings and examples, in which:

FIG. 1 is a flow chart of a method of an embodiment of the present invention;

FIG. 2 is a histogram of soft porosity distribution between salts of an embodiment of the present invention;

FIG. 3 is a graph showing the comparison of predicted and measured longitudinal wave velocities of different dry rock models of a rock salt and a shale layer between the rock salt according to an embodiment of the invention;

FIG. 4 is a schematic diagram of soft pore distribution at different pressures based on log data fitting dry rock velocity and pressure change relationships and inverting the same in an embodiment of the present invention;

FIG. 5 is a diagram showing a comparison of the predicted results of the petrophysical model of well 1 and the measured results of the well logging according to an embodiment of the present invention;

FIG. 6 is a schematic diagram showing a comparison of the predicted result of the shallow rock physical model of the well 2 with the measured result of the well logging according to the embodiment of the present invention;

FIG. 7 is a diagram showing a comparison of the predicted results of the physical model of the deep rock of the well 2 with the measured results of the well logging according to the embodiment of the present invention.

Detailed Description

The present invention will be described in further detail with reference to the following examples in order to make the objects, technical solutions and advantages of the present invention more apparent. It should be understood that the specific embodiments described herein are for purposes of illustration only and are not intended to limit the scope of the invention.

As shown in fig. 1, a shale oil reservoir rock physical modeling method for inverting pore parameters based on logging data comprises the following steps:

the first step: laboratory testing to obtain key parameters of mineral and dry rock models

The core sample density, the porosity, the XRD mineral content and the laboratory test broadband longitudinal and transverse wave speed (ultrasonic 1MHz and low frequency 1-3000 Hz) are obtained through X-diffraction whole rock test, physical property test and petrophysical acoustic test. And determining the physical properties and elasticity (anisotropy and dispersion) characteristics of the stratum by combining and comparing the logging target interval data, and determining the basis for selecting key parameters of minerals and dry rocks.

And a second step of: dry rock models of rock salt and interrock shale are preferred

Based on laboratory core test data (mineral composition, density, porosity, ultrasonic longitudinal and transverse wave speeds under different pressures of drying and fluid saturation conditions, and the like), the ultra-high pressure speed is obtained by fitting a pressure relation of the ultrasonic test speed. The very high pressure velocity corresponds to the soft pores being fully closed, the rock containing only hard pores, whereas with a gradual decrease in pressure (reverse release) the closed soft pores are gradually opened. Therefore, by taking a skeleton which only contains hard holes at extremely high pressure as a matrix, we can simulate the soft porosity phi at each pressure point of the depressurization process (soft holes gradually open) through model inversion _c And aperture aspect ratio alpha _c (see FIG. 2). By a nonlinear least square inversion method, the input parameters (matrix and total porosity) are ensured to be the same, and multiple pore distribution phi is inverted by comparing different equivalent medium theoretical models (MT, KT, SCA, DEM) _c ，α _c And a hard pore aspect ratio alpha _s As a result, the matching effect of the predicted data and the measured data is preferably suitable for the equivalent medium models of the rock salt and the shale stratum between the salt respectively. The following is an inversion formula:

in the method, in the process of the invention,representing longitudinal wave speeds at different microcrack porosities and microcrack hole aspect ratios simulated by different equivalent medium models; />Fitting longitudinal wave speeds under different pressures for ultrasound; />Simulating longitudinal wave speeds only containing hard holes on the basis of different equivalent medium models; />Fitting the ultrasonic wave with the high-pressure longitudinal wave speed; epsilon _vp The minimum relative error for the simulated and ultrasound measured fit data is less than 0.001. Wherein the aspect ratio of the hard pores alpha _s Interval is [0.001,0.3 ]]. The soft porosity (%) and microcrack aspect ratio ranges from [0,0.0005 ], respectively]，[0，0.002]。

As a result of this step, compared with KT model and MT model, we prefer that DEM (differential equivalent medium theory) model is more suitable for skeletal modulus calculation of salt rock stratum (see fig. 3 (a)); the SCA (self-compatible approximation) model is more suitable for the calculation of the skeletal modulus of the interbed shale formation (see fig. 3 (b)). This process is a process that others do not do when the model is selected.

And a third step of: and establishing the relation between the elastic modulus and the pressure of the dry rock with different lithology.

This step is a key point where the present technique flow may be applied to logging data. It should be noted here that the velocity versus pressure change relationship of the ultrasonic test dry rock can be obtained for core data (step two), however, there is no direct pressure information for logging data, and thus the soft pore closure process cannot be simulated. The conventional logging prediction is performed by using a petrophysical model, and only experience parameters of soft pores can be manually given, so that the relations of different lithology rock speeds and pressures are extracted from the well, and the content is briefly described as follows:

(1) According to the well-connected profile, depth and acoustic logging speed data points of different wells and different lithologies in the same stratum are extracted, depth values are converted into pressure values through pressure gradients (1 MPa/100 m), logging acoustic speed is converted into saturated rock bulk modulus by combining logging density, and then data points of pressure-bulk modulus are fitted to obtain a relation formula of full-range pressure and bulk modulus (saturation):

wherein: f (F) _fit To fit a function, P _well To extract pressure points in the well, K _well The saturated bulk modulus calculated for the extracted sonic velocity in the well,the resulting saturated rock bulk modulus at any pressure at the same lithology (either rock salt or intershale) was fitted.

(2) The variation of the bulk modulus of dry rock with pressure (arbitrary pressure) can be based on equation (3)The result of (2) is obtained by fluid replacement, and the calculation formula is as follows

Wherein:is the bulk modulus of dry rock at any pressure at the same lithology; phi is the porosity of the well log, K _f Is the bulk modulus of the fluid. K (K) _m Is the bulk modulus of the matrix.

Finally we get the shape between the bulk modulus of dry rock and the full range of pressureIs a fitting relation of:

taking dolomite mudstone as an example, the fitting relation is as follows

Wherein: p (P) _i The unit is MPa and the unit is that,the unit is GPa.

Fourth step: construction of multiple pore parameters dry rock model

Establishing an objective function according to the dry rock bulk modulus and the pressure relation obtained in the third step through an equivalent medium theoretical model simulation result and the dry rock bulk modulus under different pressures, and inverting to obtain the aspect ratio alpha of a single hard pore in the well _s Aspect ratio parameter alpha of multiple microcrack _c And a corresponding soft porosity phi _c (α _c ) Distribution.

(1) Calculation of hard pore aspect ratio alpha _s

Assuming that the rock consists of a rock matrix, hard pores (aspect ratio alpha _s Hard pore phi _s ) Microcrack (soft pore aspect ratio alpha) _c Soft porosity phi _c ) Composition, wherein the rock has a total porosity phi and a hard porosity phi _s And soft porosity phi _c The relationship of (2) can be expressed as: phi=phi _s +φ _c . When the rock is at extremely high pressure, the soft pores are all closed, so the rock is composed of only matrix and hard pores, and the rock bulk modulus is equivalent to that of the dry rock in the extremely high pressure state in formula (5).

In addition, the matrix and the hard pores (alpha) are input by using an equivalent medium model _s ，φ _s ) Theoretical simulation results can be obtained, so that an objective function can be established between the extremely high pressure state bulk modulus of the dry rock of the formula (5) and the model simulation results, and the aspect ratio of the hard pores can be inverted.

In the method, in the process of the invention,simulating high-pressure bulk modulus, < + >, representing equivalent media model>For dry rock of formula (4) extremely high pressure bulk modulus (i.e. by +.>Fitting the resulting extreme pressure results). Epsilon _K The range is less than 0.001 for relative error.

The inversion of the aspect ratio of the hard pores requires the known hard porosity to obtain the microcrack porosity phi _c Further find the hard porosity phi _s ＝φ-φ _c The micro-crack porosity phi is as follows _c And microcrack aspect ratio alpha _c The acquisition process comprises the following steps:

(2) Calculating micro-crack porosity phi _c And microcrack aspect ratio alpha _c

Assuming that the rock contains only one set of microcracks, the fracture density of the set of microcracks is defined as:

in the method, in the process of the invention,the fracture density and V are the rock volume; n is the number of microcracks in the rock and a is the major axis of the microcracks.

Micro-crack porosity phi _c Represented as

Wherein,is the fracture density and α is the microcrack aspect ratio.

For rock with a single pore structure, the fracture density has the following relation with an equivalent medium model:

DEM model applied to salt rock stratum, and the relation between rock equivalent modulus and fracture density is that

In the method, in the process of the invention,equivalent bulk modulus and shear modulus, respectively, +.>Is equivalent to Poisson's ratio, K _m Bulk modulus for background matrix; v _m Poisson's ratio for background matrix, +.>Is a fracture density parameter.

SCA model applied to salt-to-salt stratum, the relation between the rock equivalent modulus and the fracture density is that

In the method, in the process of the invention,equivalent volume and shear modulus, respectively; k (K) _m ，μ _m The background basal volume and the shear modulus, respectively; />Is equivalent to poisson's ratio->Is a fracture density parameter.

When the rock has N groups of different pore aspect ratios alpha _i And has an initial pore aspect ratio of alpha ₀ . When the rock is subjected to an increasing pressure, the microcracks of minimum pore aspect ratio close first until the pressure increases until the N groups of microcracks are all closed, at which point the rock consists essentially of matrix and hard pores. The influence of the process bulk modulus by pressure is mainly related to the closure of micro cracks, so that the initial aspect ratio of the cracks after opening under different pressures can be obtained by a depressurization mode to be alpha ₀ (p _N ) Fracture density of microcrack of (C)Calculating each pressure point P through the single pore structure model of formulas (9) and (10) _i Crack density +.contained under (i=1:N)>Is the equivalent bulk modulus of the input matrix K _m Is P _N Fitting modulus under pressureThe input equivalent modulus is P _N-1 Fitting modulus under pressure +.>Repeating the nonlinear least square inversion algorithm to obtain the crack density of N groups of microcracks>

In the method, in the process of the invention,and->Respectively, an initial aspect ratio alpha ₀ (p _i ) Crack Density->Calculating an equivalent bulk modulus by an equivalent medium theoretical model; />And->Is the pressure P _i The corresponding fitting bulk modulus. Epsilon ₁ And epsilon ₂ The relative error in inversion of the rock salt and the shale between the salts is less than 0.0001. In addition, crack Density->The inversion interval size is [0,0.6 ]]。

The fracture density of N groups of microcracks can be obtained through the above processesThereby calculating the cumulative fracture density of the rock>Is that

Wherein the left side is the right side summation result,represents->The sum of the fracture densities of all microcracks.

Finally byCumulative fracture density of rock salt and interbalted shale formationsFitting high pressure bulk modulus in wellAnd bulk modulus at arbitrary pressure +.>We can calculate and obtain the micro-fracture aspect ratio distribution alpha of the rock salt and the shale stratum between the salt at any pressure _c And micro-crack porosity phi _i ：

α _c ＝α ₀ (p _i+1 )-α ₀ (p _i )，α ₀ (p _i+2 )-α ₀ (p _i )，…，α ₀ (p _N )-α ₀ (p _i )

(14)

Wherein alpha is ₀ (p _i ) Representing different microcrack initial aspect ratios; alpha _c Represents the microcrack aspect ratio at any closure pressure; phi (phi) _i (α _c ) Is a porosity distribution of different microcrack aspect ratios at arbitrary closure pressures. Summing the right side of (15) can obtain the micro-crack total porosity phi under any pressure _c

In conclusion, the single hard pore aspect ratio alpha of any depth (pressure) of different stratum in the well can be obtained through the inversion of the bulk modulus of the fitted dry rock in the well and the equivalent medium model _s Aspect ratio parameter alpha of multiple microcrack _c And a corresponding soft porosity phi _c (α _c ) Distribution. Whereby the parameter is brought into the well model for positive workingAnd (5) performing.

(3) Dry rock model construction of multiple pore parameters

Based on the above steps, formation pore structure parameters of rock salt and inter-salt shale such as multiple microcrack aspect ratio parameter α have been obtained _c And a corresponding soft porosity phi _c (α _c ) The distribution is that we can take the logging data (mineral content, porosity, saturation) and the inversion parameters (corresponding to different depth point data in the well) as input, and take the data into DEM model and SCA model to obtain the dry rock skeleton modulus of each depth point of the shale stratum between salt rock and salt.

Fifth step: fluid displacement model considering dispersion

According to the second step, no dispersion exists in the salt rock, and the shale layer between the salt rock has dispersion. Thus, when the fluid displacement model is carried out, the fluid displacement model is constructed by adopting a mode of rock salt and interlayer lithology modeling. The salt rock layer selects a Gassmann fluid displacement model to realize the calculation of the saturated fluid rock elastic modulus of the salt rock layer. The Gassmann equation is suitable for estimating the change in the overall elastic modulus of the rock due to the change in pore fluid at low frequencies.

A broadband experiment test proves that the shale between the salt shale has horizontal micro cracks, and the fluid flow among different cracks causes velocity dispersion, so that the micro crack porosity phi in the rock _c Pore aspect ratio parameter alpha _c The effect of soft pore fluid relaxation on rock stiffness can be described, and dry rock containing only hard pores (partial microcrack closure) under a certain pressure is equivalent to a new matrix, namelySoft pores (alpha) of saturated fluid are then added to the matrix _c And phi _c ) Thereby characterizing the jet action. Thus, since the remaining dry hard pores in the rock are insensitive to pressure changes, the remaining pores (α _s And phi _s ) Fluid replacement into hard pores by low frequency Gassmann equation, so the bulk modulus K of rock at full saturation at arbitrary pressure _Saturation And shear modulus G _Saturation The expression of the change along with the frequency is：

Wherein the method comprises the steps ofIs the bulk modulus of the rock matrix, replaced by the bulk modulus of the dry rock fitted at any pressure; phi (phi) _c (p) represents the total porosity of the microcrack at an effective pressure; note here that α for computational convenience _c The soft pore aspect ratio corresponding to the maximum of the porosity in the microcrack aspect ratio distribution. η is the pore fluid viscosity coefficient and ω is the circular frequency.And->The method is characterized in that the method is used for representing the bulk modulus and the shear modulus of a dry rock skeleton under a certain pressure of the rock salt and the shale between the salt, and the dry rock skeleton and the shear modulus are obtained by the SCA model and the DEM model respectively. />To fit the bulk modulus of extremely high pressure dry rock in the well.

Sixth step: the rock physical dispersion model based on the established multiple pore structure parameters is applied in the well, namely longitudinal and transverse wave speed prediction and applicability analysis.

When the petrophysical model is verified, the mineral component content, the porosity and the saturation data in the logging interpretation result of the oil-containing actual measurement longitudinal and transverse wave data well are mainly used as input data and substituted into the established petrophysical modeling flow (in the first five steps) to predict the elasticity attribute of the fluid-saturated rock. The method is characterized in that the prediction data of the forward result logging frequency band (10 kHz) is taken to carry out comparison analysis with the logging actual measurement elastic attribute, so that the same-frequency comparison is realized, and the accuracy and the applicability of the modeling method are verified.

FIG. 1 is a flow chart of a petrophysical modeling method based on inversion pore structure of logging data, according to the flow chart, we combine basic physical property data of laboratory core test and acoustic velocity data of different pressures to perform optimization of equivalent medium models, and determine a dry skeleton model of a shale layer between salt rocks and salt; and then acquiring the relation of the dry rock skeleton speed in the well along with the pressure change based on lithology-depth-speed information of logging data and a reverse flow body replacement theory, respectively carrying out pore structure parameter inversion by using a DEM model and an SCA model, acquiring the micro-crack soft porosity and the multiple pore aspect ratio in the well of the salt rock and the shale, and re-taking the result into the dry skeleton model. Finally we calculated the elastic modulus of the fluid saturated rock with the Gassmann fluid replacement model and the Boris Gurevich modified jet model, respectively.

TABLE 1 basic physical Properties of typical cores for rock salt and interbalided shale layers

We fit the different lithologic rock velocities and pressure relationships in the well by a fitting formula as shown in fig. 4 (a), thereby obtaining the velocities of the high pressure conditions. Fig. 4 (b) is an inversion of the dry matrix modulus and SCA model of the intersalted shale at different pressures obtained by fitting, the resulting micro-fracture porosity and aspect ratio distribution at different pressures, and the result is taken into the dry matrix model and equation (4) to calculate the shale rock saturated fluid elastic modulus.

Examples: application field and application prospect:

all other embodiments, which can be made by those skilled in the art without making any inventive effort, are intended to be within the scope of the present invention, based on the examples herein.

Fig. 5, 6 and 7 are illustrations of application and verification of petrophysical modeling methods implemented by the present technology in shale oil formation logging data. And based on logging interpretation mineral content data, porosity, saturation and the like, inverting soft porosity and pore structure parameters as input, predicting and comparing the measured data of the longitudinal and transverse waves of the shale layer between the salt rock and the shale layer in different shale oil wells.

For 1 well, the average error of petrophysical modeling results and measured results of longitudinal and transverse wave speeds are 92m/s and 107m/s respectively, and the correlation coefficients are 0.94 and 0.90 respectively.

The average errors of the petrophysical modeling results and the actual measurement results of the longitudinal wave speed and the transverse wave speed of the 2-well shallow layer are 88m/s and 96m/s respectively, and the correlation coefficients are 0.92 and 0.89 respectively.

Wherein the average errors of the petrophysical modeling result and the actual measurement result of the longitudinal wave speed and the transverse wave speed of the 2-well deep layer are 102m/s and 114/s respectively, and the correlation coefficients are 0.90 and 0.88 respectively.

In conclusion, the petrophysical modeling method is considered to meet the actual shale oil stratum characteristics through the actual comparison effect and the error accuracy analysis, so that the acoustic wave velocity in the well can be predicted more accurately, and support can be provided for geophysical accurate well logging interpretation evaluation and seismic petrophysical analysis.

It will be understood that modifications and variations will be apparent to those skilled in the art from the foregoing description, and it is intended that all such modifications and variations be included within the scope of the following claims.

Claims (6)

1. The shale oil reservoir rock physical modeling method based on the inversion pore parameters of the logging data is characterized by comprising the following steps of:

1) Obtaining the density, the porosity, the XRD mineral content and the broadband ultrasonic longitudinal and transverse wave speed of a laboratory test core sample through experimental tests; determining stratum physical properties and elasticity characteristics by combining the target interval data of the comparison logging;

2) Based on core test data, fitting an ultrasonic test speed-pressure relation to obtain an extremely high pressure speed, and simulating soft porosity phi at each pressure point in the depressurization process through model inversion _c And aperture aspect ratio alpha _c The method comprises the steps of carrying out a first treatment on the surface of the According to the simulation data, selecting equivalent medium models respectively suitable for the rock salt and the intersalic shale stratum;

3) Extracting the speed and pressure relations of different lithology rocks in a well to obtain a fitting relation between the bulk modulus of the dry rock and the full-range pressure;

4) Calculating a hard pore aspect ratio, a micro-crack porosity and a micro-crack aspect ratio according to the experimental test data and the logging data in the step 1), and constructing a dry rock model with multiple pore parameters according to lithology;

5) Constructing a fluid displacement model by adopting a mode of rock salt and interlayer lithology modeling;

bulk modulus K of rock at full saturation at arbitrary pressure _Saturation And shear modulus G _Saturation The expression as a function of frequency is:

wherein,is the bulk modulus of the rock matrix, replaced by the bulk modulus of the dry rock fitted at any pressure; phi (phi) _c (p) represents the total porosity of the microcrack at an effective pressure; eta is the viscosity coefficient of the pore fluid, omega is the circular frequency, < ->And->Represents the bulk modulus and the shear modulus of the dry rock framework under certain pressure of the rock salt and the shale between the salt, and the +.>To fit the bulk modulus of extremely high pressure dry rock in the well.

2. The method for physical modeling of shale oil reservoir rock based on inversion of pore parameters of logging data according to claim 1, wherein in the step 2), equivalent medium models of the shale rock and the intersalic stratum are a SCA model and a DEM model, respectively.

3. The method for physical modeling of shale oil reservoir rock based on inversion of pore parameters of logging data according to claim 1, wherein said step 3) is specifically as follows:

3.1 Extracting depth and acoustic logging speed data points of different wells and different lithologies in the same stratum according to the well connecting profile, converting the depth value into a pressure value through a pressure gradient, converting the logging acoustic speed into a saturated rock bulk modulus in combination with logging density, and fitting the data points of the pressure-bulk modulus to obtain a relation formula of full-range pressure and the saturated bulk modulus:

wherein: f (F) _fit To fit a function, P _well To extract pressure points in the well, K _well The saturated bulk modulus calculated for the extracted sonic velocity in the well,the saturated rock bulk modulus under any pressure under the same lithology is obtained by fitting;

3.2 Based on a)As a result of fluid replacement, the relation of the change of the dry rock bulk modulus with the pressure is obtained:

wherein:is the bulk modulus of dry rock at any pressure at the same lithology; phi is the porosity of the well log, K _f For bulk modulus of fluid, K _m Is the bulk modulus of the matrix;

the fit relationship between the bulk modulus of the dry rock and the full range of pressures can be obtained.

4. The method for physical modeling of shale oil reservoir rock based on inversion of pore parameters of logging data according to claim 2, wherein the following is specific in the step 4):

4.1 According to the relation between the dry rock bulk modulus and the pressure obtained in the step 3), establishing an objective function through an equivalent medium theoretical model simulation result and the dry rock bulk modulus under different pressures, and inverting to obtain the aspect ratio alpha of a single hard pore in the well _s Aspect ratio parameter alpha of multiple microcrack _c And a corresponding soft porosity phi _c (α _c ) Distribution;

4.2 Taking logging data and inversion parameters obtained in the step 4.1) as inputs, respectively carrying the logging data and inversion parameters into the equivalent medium model determined in the step 2), and obtaining the dry rock skeleton modulus of each depth point of the shale stratum between the salt rocks and the salt.

5. The method for physical modeling of shale oil reservoir rock based on inversion of pore parameters of logging data as claimed in claim 4, wherein the calculation of the hard pore aspect ratio in step 4.1) is performed by the following method:

it is assumed that the rock consists of a rock matrix, hard pores and micro-cracks, wherein the total porosity phi and the hard porosity phi of the rock _s And soft porosity phi _c The relation of (2) is expressed as: phi=phi _s +φ _c ；

When the rock is under extremely high pressure, the soft holes are all closed, so the rock is composed of a matrix and hard pores, and the rock bulk modulus is equal to the bulk modulus of the dry rock in the extremely high pressure state in the step 3.2);

establishing an objective function according to the fitting relation between the obtained dry rock bulk modulus and the full range pressure, inverting the aspect ratio alpha of the hard pore _s ；

In the method, in the process of the invention,simulating high-pressure bulk modulus, < + >, representing equivalent media model>To fit the resulting extremely high pressure bulk modulus, ε, of the dry rock _K The range is less than 0.001 for relative error.

The precondition for achieving inversion of the aspect ratio of the hard pores requires a known hard porosity phi _s Hard porosity phi _s ＝φ-φ _c 。

6. The method for physical modeling of shale oil reservoir rock based on inversion of pore parameters of logging data as claimed in claim 5, wherein the micro-crack porosity phi _c And microcrack aspect ratio alpha _c The acquisition process is as follows:

acquiring the crack density of the rock according to an equivalent medium model of the rock and the intersalt shale stratum, calculating the cumulative crack density of the rock, and finally respectively calculating and obtaining the micro-crack aspect ratio distribution alpha of the rock and the intersalt shale stratum under any pressure by the cumulative crack density of the rock and the intersalt shale stratum, the fitting high-pressure volume modulus in a well and the volume modulus under any pressure _c And micro-crack porosity phi _i 。