Carbonate rock pore pressure prediction method and device based on pore volume increment

Abstract

The invention discloses a carbonate rock pore pressure prediction method and device based on pore volume increment, and relates to the technical field of oil and gas reservoir exploration, and the key point of the technical scheme is that carbonate rock is regarded as an elastomer, and based on Hooke's law, the correlation between the rock pore compression coefficient and the rock pore pressure and pore volume is deduced; a compact carbonate rock formation pore pressure prediction model is established, a prediction model parameter rock pore compression coefficient can be obtained by analyzing a Hall (1953) experiment statistical result, and other parameters can be obtained by utilizing logging information or calculating empirical values in combination with the condition of a test area. Compared with the prior art, the novel carbonate rock formation pore pressure prediction method has the advantages that the number of required calculation parameters is small, the data acquisition cost is low, calculation is easy and convenient, the true situation of the pore pressure of a carbonate rock reservoir with high heterogeneity can be accurately predicted, and the method has important industrial application value in oil-gas exploration and evaluation.

Description

Technical Field

[0001] The invention relates to the technical field of oil and gas reservoir exploration, and more particularly to a method and device for predicting carbonate rock pore pressure based on pore volume increment. Background Art

[0002] In recent years, with the continuous increase in the world's demand for oil and gas energy and the continuous deepening of oil and gas exploration, global oil and gas exploration has gradually shifted from conventional to unconventional, from shallow to deep and even ultra-deep, and low-permeability and ultra-low-permeability reservoirs have received widespread attention and continuous breakthroughs.

[0003] Unlike other parts of the world, low-permeability reservoirs are widely developed in my country, and the lithology mainly includes clastic rocks and carbonate rocks. The carbonate diagenesis not only has early chemical and biological cementation, mechanical and biological mixing, but also is accompanied by recrystallization, dolomite, dissolution, etc. of later sedimentary transformation, which is fundamentally different from clastic rocks dominated by mechanical compaction, making the pore space of carbonate rocks undergo complex evolution, with diverse pore types and multiple heterogeneities. This complexity of lithology and physical properties makes it difficult to find a clear and regular pressure response relationship in carbonate formations on well logging curves such as acoustic waves and resistivity and seismic data. When drilling into carbonate formations, due to the difficulty in predicting abnormal pressure, it often causes complex underground accidents such as wellbore collapse, well leakage, and even blowouts. If the pore pressure of carbonate formations can be accurately predicted, it can provide a scientific basis for determining the safe drilling fluid density window, so as to effectively prevent the occurrence of complex underground accidents in carbonate formations.

[0004] At present, most of the pressure prediction methods for carbonate formations are based on the effective stress principle to establish the relationship between different carbonate rock characteristic responses and effective stress to predict the pore pressure of carbonate formations (Xia Hongquan, Cheng Yuanfang, Cui Jie, Sun Bo, Yang Shunhui and Wang Yajuan, etc.) and Atashbari et al. proposed a method to predict the pore pressure of carbonate formations using the rock volume compression coefficient. These methods provide different ideas and methods for the prediction of pore pressure in carbonate formations, but none of them take into account the characteristics of significant chemical action and multiple heterogeneity of carbonate rocks, which have certain limitations in practical application. Considering the above problems, Liu Yukun et al. analyzed the stress-strain constitutive relationship of carbonate rocks and established a theoretical model for overpressure prediction based on the elastic theory of porous media. However, the parameters of the prediction model need to be calculated by different rock physics models, which has high calculation cost and strong uncertainty.

[0005] Therefore, there is an urgent need for a widely applicable model and method to predict the pore pressure of complex and highly heterogeneous carbonate formations. Summary of the invention

[0006] To achieve the above object, the present invention provides the following technical solution: a carbonate rock pore pressure prediction method based on pore volume increment, the steps of which are as follows:

[0007] S1. Constructing a carbonate formation pore pressure prediction model:

[0008]

[0009] Where P p is the formation pore pressure, MPa. M is the volume ratio coefficient, unitless. σ is the formation vertical stress, MPa. C p is the pore compression coefficient, unitless. p is the porosity, %. E is the Young's modulus, MPa. 0 is the hydrostatic pressure, MPa.

[0010] S2. Based on the carbonate formation data of at least one well in the study area, obtain the P of the well. p ,σ,C p ,φ p , E, P 0 , the actual drilling P p ,σ,C p ,φ p , E, P 0 It is brought into the carbonate formation pore pressure prediction model to fit the value of M.

[0011] S3. According to the carbonate formation data of the wells to be predicted in the study area, obtain the σ and C of the wells to be predicted. p ,φ p , E, P 0 , the σ and C of the well to be predicted p ,φ p , E, P 0 The M fitted with S2 is brought into the carbonate formation pore pressure prediction model, and the calculated P p That is the pore pressure of the carbonate formation to be predicted for drilling.

[0012] The present invention is further configured as follows: the carbonate formation pore pressure prediction model in S1 adds the influence of regional tectonic stress on pore pressure σ tv :

[0013]

[0014] In the formula, σ tv It is a stress additional term, which is related to the tectonic stress in the study area, MPa.

[0015] M and σ are fitted in S2 tv The value of .

[0016] In S3, M and σ fitted by S2 are tv The value of is brought into the carbonate formation pore pressure prediction model to calculate P p .

[0017] The present invention is further configured as follows: the pore compression coefficient C p The calculation formula is as follows:

[0018]

[0019] In the formula, the porosity φ p Obtained through the interpretation of logging data, A and B are constants with given values.

[0020] The present invention is further configured as follows: A is A1×10 -4 .

[0021] The present invention is further configured to: obtain multiple core samples of carbonate rock formations in the study area, obtain the porosity and corresponding pore compression coefficient of each core sample through experiments, and fit the values ​​of A1 and B based on the data of these core samples.

[0022] The present invention is further configured as follows: the porosity and the corresponding pore compression coefficient of each core sample are plotted on a Hall chart, and the values ​​of A1 and B are fitted.

[0023] The present invention is further configured such that: A1 and B are both taken to three decimal places.

[0024] The present invention is further configured as follows: A1 is 1.796, and B is 0.439.

[0025] The present invention is further configured such that: the vertical stress of the formation is equal to the pressure of the overlying formation.

[0026] The present invention is further configured as follows: the calculation formula of the overlying formation pressure is as follows:

[0027]

[0028] Where g is the acceleration due to gravity, 9.8N / kg, H 0 and H 1 are the starting depth and ending depth of the target well section, m. ρ av and ρ are the average density of the overburden and the density of the target well section, kg / m 3 , obtained through density logging curve.

[0029] The present invention is further configured as follows: the calculation formula of the Young's modulus E is as follows:

[0030]

[0031] Where ρ is the formation density, kg / m 3 , obtained through density logging curve. VP and VS are P-wave velocity and S-wave velocity, respectively, m / s, obtained through sonic logging curve.

[0032] The present invention is further configured as follows: the hydrostatic pressure P 0 The calculation formula is as follows:

[0033] P 0 =g×ρ w ×H

[0034] Where g is the acceleration due to gravity, 9.8 N / kg, and H is the depth of the formation, m. w is the average density of the pore water in the overlying formation, kg / m3, obtained by analyzing the actual formation water mineralization data.

[0035] The present invention is further configured such that: M is greater than 1.

[0036] The present invention is further configured as follows: the above two carbonate rock formation pore pressure prediction models are both applicable to dense carbonate rock formations with developed overpressure.

[0037] The present invention also provides a carbonate rock pore pressure prediction device based on pore volume increment, which includes a storage medium and a processor, wherein a computer program is stored on the storage medium. The processor is used to implement the carbonate rock pore pressure prediction method based on pore volume increment when executing the computer program.

[0038] In summary, the present invention has the following beneficial effects compared with the prior art: the present invention regards carbonate rock as an elastic body, and based on Hooke's law, derives the correlation between rock pore compression coefficient and rock pore pressure and pore volume, and establishes a dense carbonate formation pore pressure prediction model. The prediction model parameter rock pore compression coefficient can be obtained by analyzing the statistical results of Hall's (1953) experiment, and other parameters can be obtained by using logging data or calculating empirical values ​​in combination with the regional conditions of the test area. This is a new method for predicting pore pressure in carbonate formations, which requires fewer calculation parameters than previous methods, has a lower data acquisition cost, is simple to calculate, and can accurately predict the true situation of pore pressure in carbonate reservoirs with strong heterogeneity, and has important industrial application value in oil and gas exploration and evaluation. BRIEF DESCRIPTION OF THE DRAWINGS

[0039] Figure 1 This is the prediction result diagram of the pore pressure prediction of a typical well in an overpressured carbonate formation using the carbonate pore pressure prediction method based on pore volume increment. DETAILED DESCRIPTION

[0040] The technical solution of the present invention will be clearly described below in conjunction with the accompanying drawings. Obviously, the described embodiments are not all embodiments of the present invention, and all other embodiments obtained by ordinary technicians in the field without making creative work are within the scope of protection of the invention.

[0041] Example

[0042] In a preferred embodiment of the present invention, a carbonate rock pore pressure prediction method based on pore volume increment comprises the following steps:

[0043] S 1. Construct a pore pressure prediction model for carbonate formations with overpressure development:

[0044]

[0045] Where P p is the formation pore pressure, MPa. M is the volume ratio coefficient, unitless. σ is the formation vertical stress, MPa. C p is the pore compression coefficient, unitless. tv It is a stress additional term, which is related to the tectonic stress in the study area, MPa. p is the porosity, %. E is the Young's modulus, MPa. 0 is the hydrostatic pressure, MPa.

[0046] S2. Based on the carbonate formation data of at least one well in the study area, obtain the P of the well. p ,σ,C p ,φ p , E, P 0 , the actual drilling P p ,σ,C p ,φ p , E, P 0 Bring it into the carbonate formation pore pressure prediction model to fit M and σ tv The value of M is greater than 1.

[0047] S3. According to the carbonate formation data of the wells to be predicted in the study area, obtain the σ and C of the wells to be predicted. p ,φ p , E, P 0 , the σ and C of the well to be predicted p ,φ p , E, P 0 M and σ fitted with S2 tv The pore pressure prediction model of carbonate formations is used to calculate P p That is the pore pressure of the carbonate formation to be predicted for drilling.

[0048] Specifically, the pore compression coefficient C p The calculation formula is as follows:

[0049]

[0050] In the formula, the porosity φ p The result is obtained by interpreting the logging data, and A and B are constants with given values. In this embodiment, A is A1×10 -4 .

[0051] By obtaining multiple core samples of carbonate formations in the study area, experiments were conducted to obtain the porosity and corresponding pore compression coefficient of each core sample, and the porosity and corresponding pore compression coefficient of each core sample were plotted on the Hall chart to fit the values ​​of A1 and B, where A1 and B were both taken to three decimal places. In this embodiment, A1 is 1.796 and B is 0.439.

[0052] Specifically, in the carbonate rock formation pore pressure prediction model, the vertical formation stress is equal to the overlying formation pressure, and the calculation formula of the overlying formation pressure is as follows:

[0053]

[0054] Where g is the acceleration due to gravity, 9.8N / kg, H 0 and H 1 are the starting depth and ending depth of the target well section, m. ρ av and ρ are the average density of the overburden and the density of the target well section, kg / m 3 , obtained through density logging curve.

[0055] Specifically, the calculation formula of the Young's modulus E is as follows:

[0056]

[0057] Where ρ is the formation density, kg / m 3 , obtained through density logging curve. VP and VS are P-wave velocity and S-wave velocity, respectively, m / s, obtained through sonic logging curve.

[0058] Specifically, the hydrostatic pressure P 0 The calculation formula is as follows:

[0059] P 0 =g×ρ w ×H

[0060] Where g is the acceleration due to gravity, 9.8 N / kg, and H is the depth of the formation, m. wis the average density of the pore water in the overlying formation, kg / m3, obtained by analyzing the actual formation water mineralization data.

[0061] The principle of the carbonate formation pore pressure prediction model in this embodiment is as follows:

[0062] For a fully saturated carbonate rock unit, the rock volume is V, and the rock pore pressure under hydrostatic pressure is equal to the hydrostatic pressure P 0 , the rock porosity is φ 0 , pore volume V p V×φ 0 Assume that the pore pressure is given by P 0 Increase to P p The pore pressure increment is ΔP p , the porosity is changed from the original φ 0 Increase to φ p At this time, the rock pore compression coefficient C p According to the definition, it is expressed as:

[0063]

[0064] In the formula, C p is the rock pore compression coefficient; φ p is the porosity when overpressure develops; V is the rock volume; ΔV p is the change in pore volume; ΔP p is the rock pore pressure increment.

[0065] Carbonate rocks are in a closed pressure system in the formation, and the change in rock volume caused by fluid pressure belongs to the strain within the elastic limit of the rock. Therefore, the strain ε of the rock volume is expressed according to Hooke's law as:

[0066]

[0067] Where ΔV is the volume change of rock; σ is the vertical stress of the formation; and E is the Young's modulus of rock.

[0068] Combining formulas (1) and (2) we get:

[0069]

[0070] Where P p is the rock pore pressure when overpressure develops; P 0 is the hydrostatic pressure.

[0071] Since carbonate rocks have a dense and rigid rock skeleton, the fluid volume expansion caused by overpressure development is unlikely to cause the rock volume to change by the same amount, that is, the fluid expansion volume change (pore volume change ΔV p) is greater than the rock volume change ΔV, so the volume ratio coefficient M (M>1) is introduced to express the ratio of its change, and the volume ratio coefficient M is:

[0072]

[0073] Substituting formula (4) into formula (3) we can get the rock pore pressure increment ΔP p The simplified calculation formula is:

[0074]

[0075] In the actual formation pressure calculation, the influence of regional tectonic stress on pore pressure also needs to be considered. Therefore, the optimal carbonate formation pore pressure prediction model is:

[0076]

[0077] This embodiment also provides a carbonate rock pore pressure prediction device based on pore volume increment, which includes a storage medium and a processor, wherein the storage medium stores a computer program. The processor is used to implement the carbonate rock pore pressure prediction method based on pore volume increment when executing the computer program.

[0078] In summary, this embodiment regards carbonate rock as an elastic body, and based on Hooke's law, derives the correlation between rock pore compression coefficient and rock pore pressure and pore volume, and establishes a dense carbonate formation pore pressure prediction model. The prediction model parameter rock pore compression coefficient can be obtained by analyzing the statistical results of Hall's (1953) experiment, and other parameters can be obtained by using logging data or calculating empirical values ​​in combination with the regional conditions of the test area. This is a new method for predicting pore pressure in carbonate formations. Compared with previous methods, it requires fewer calculation parameters, has lower data acquisition costs, and is simple to calculate. Figure 1 As shown, it can accurately predict the true pore pressure of carbonate reservoirs with strong heterogeneity, and has important industrial application value in oil and gas exploration and evaluation.

[0079] The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. For those skilled in the art, the present invention may have various modifications and variations. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present invention shall be included in the protection scope of the present invention.

Claims

1. Carbonate rock pore pressure prediction method based on pore volume increment, Features: S1. Constructing a carbonate formation pore pressure prediction model: Where P p is the formation pore pressure, MPa; M is the volume ratio coefficient, unitless; σ is the formation vertical stress, MPa; C p is the pore compressibility coefficient, unitless; φ p is the porosity, %; E is Young's modulus, MPa; P 0 is the hydrostatic pressure, MPa; S2. Based on the carbonate formation data of at least one well in the study area, obtain the P of the well. p ,σ,C p ,φ p , E, P 0 , the actual drilling P p ,σ,C p ,φ p , E, P 0 Bring it into the carbonate formation pore pressure prediction model and fit the value of M; S3. According to the carbonate formation data of the wells to be predicted in the study area, obtain the σ and C of the wells to be predicted. p ,φ p , E, P 0 , the σ and C of the well to be predicted p ,φ p , E, P 0 The M fitted with S2 is brought into the carbonate formation pore pressure prediction model, and the calculated P p That is the pore pressure of the carbonate formation to be predicted for drilling.

2. The carbonate rock pore pressure prediction method based on pore volume increment according to claim 1, Features: The effect of regional tectonic stress on pore pressure σ is added to the carbonate formation pore pressure prediction model in S1 tv : In the formula, σ tv is the stress additional term, which is related to the tectonic stress in the study area, MPa; M and σ are fitted in S2 tv The value of In S3, M and σ fitted by S2 are tv The value of is brought into the carbonate formation pore pressure prediction model to calculate P p .

3. The carbonate rock pore pressure prediction method based on pore volume increment according to claim 1 or 2, Features: The pore compression coefficient C p The calculation formula is as follows: In the formula, the porosity φ p Obtained through the interpretation of logging data, A and B are constants with given values.

4. The carbonate rock pore pressure prediction method based on pore volume increment according to claim 3, Features: A is A1×10 -4 .

5. The carbonate rock pore pressure prediction method based on pore volume increment according to claim 4, Features: Multiple core samples of carbonate rock formations in the study area were obtained, and the porosity and corresponding pore compression coefficient of each core sample were obtained through experiments. The values ​​of A1 and B were fitted based on the data of these core samples.

6. The carbonate rock pore pressure prediction method based on pore volume increment according to claim 5, Features: The porosity and corresponding pore compression coefficient of each core sample are plotted on the Hall chart, and the values ​​of A1 and B are fitted.

7. The carbonate rock pore pressure prediction method based on pore volume increment according to claim 4, Features: A1 and B are both rounded to three decimal places.

8. The carbonate rock pore pressure prediction method based on pore volume increment according to claim 7, Features: The A1 is 1.796 and B is 0.

439.

9. The carbonate rock pore pressure prediction method based on pore volume increment according to claim 1 or 2, Features: The vertical formation stress is equal to the overlying formation pressure.

10. The carbonate rock pore pressure prediction method based on pore volume increment according to claim 9, Features: The calculation formula of the overlying formation pressure is as follows: Where g is the acceleration due to gravity, 9.8N / kg, H 0 and H 1 are the starting depth and ending depth of the target well section, m; ρ av and ρ are the average density of the overburden and the density of the target well section, kg / m 3 , obtained through density logging curve.

11. The carbonate rock pore pressure prediction method based on pore volume increment according to claim 1 or 2, Features: The calculation formula of the Young's modulus E is as follows: Where ρ is the formation density, kg / m 3 , obtained through density logging curve; VP and VS are the longitudinal wave velocity and shear wave velocity, m / s, respectively, obtained through acoustic logging curve.

12. The carbonate rock pore pressure prediction method based on pore volume increment according to claim 1 or 2, Features: The hydrostatic pressure P 0 The calculation formula is as follows: P 0 =g×ρ w ×H Where g is the acceleration due to gravity, 9.8 N / kg, H is the depth of the formation, m; ρ w is the average density of the pore water in the overlying formation, kg / m3, obtained by analyzing the actual formation water mineralization data.

13. The carbonate rock pore pressure prediction method based on pore volume increment according to claim 1 or 2, Features: The M is greater than 1.

14. The carbonate rock pore pressure prediction method based on pore volume increment according to claim 1 or 2, Features: The carbonate formation pore pressure prediction model is applicable to dense carbonate formations with developed overpressure.

15. Carbonate rock pore pressure prediction device based on pore volume increment, Features: It comprises a storage medium and a processor, wherein the storage medium stores a computer program; the processor is used to implement the carbonate rock pore pressure prediction method based on pore volume increment as described in any one of claims 1 to 14 when executing the computer program.

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