A method and device for calculating the paleo-pressure of the entire well section of a clastic gas reservoir

Abstract

The present invention provides a method for calculating the paleo-pressure of the reservoir in the entire well section of a clastic gas reservoir. Based on the definition of the rock formation compaction coefficient and the rock skeleton compression coefficient, a theoretical formula for characterizing the change in pore volume during the geological history period is established, and physical parameter data such as rock mineral composition and porosity data are calculated using logging data. The rock skeleton compression coefficient values ​​of each geological history period are calculated through a variety of rock physics models, and then the change in pore volume in each historical period is obtained. When the reservoir is a dry gas or wet gas reservoir, the current measured reservoir pressure and temperature are used as the starting point, combined with the paleo-temperature curve of the simulated formation thermal evolution history, and then the reservoir paleo-pressure values ​​of each historical period are calculated. This method does not require any experimental testing, and can continuously calculate the paleo-pressure values ​​of each historical time period in the entire well section, playing an important role in basin analysis and oil and gas reservoir dynamics research, and has important industrial application value in oil and gas exploration and evaluation.

Description

Technical Field

[0001] The invention relates to the field of geological exploration, and in particular to a method and a device for calculating the paleo-pressure of a full-well reservoir of a clastic gas reservoir. Background Art

[0002] The restoration of paleopressure in sedimentary basins is an important part of basin analysis and reservoir dynamics research, and plays an important role in oil and gas geological research and exploration. The research on the restoration of paleopressure is to calculate the pore pressure or pore pressure coefficient of the formation in each geological historical period during the uplift process of the reservoir based on the existing geological data, analytical test data and the history of formation deposition and burial.

[0003] A variety of methods for restoring paleopressure have been developed, which can be roughly divided into the following categories: (1) Using fluid inclusions to restore formation paleopressure, the paleopressure at the time of fluid capture is obtained by using the equilibrium relationship between the homogenized temperature and fluid composition of hydrocarbon inclusions and brine inclusions of the same period. Common methods include: calculating the paleopressure of oil inclusions through PVT-sim software and calculating the paleopressure of methane inclusions by laser Raman shift. These methods require a large number of hydrocarbon inclusions that can be observed and measured under a microscope, and are not applicable to reservoirs with few or small inclusions. (2) Using mudstone acoustic time difference data, based on the principle of irreversible mudstone compaction, the paleopressure at the maximum burial depth of the formation can be deduced. Common methods include the equivalent depth method and the Fillippone formula method. These methods can only estimate the formation pore pressure except for the maximum burial depth of the formation. (3) Using PetroMod, BasinMod, etc. Basin simulation software such as , can be used to restore the paleopressure characteristics of single wells, profiles and planes. This method is based on the backstripping model. In order to obtain reasonable calculation results, a large amount of evolution data from geological history is often required. However, these data are difficult to obtain and require a lot of debugging and testing. (4) For carbonate rock formations that lack oil inclusions and brine inclusions containing gaseous hydrocarbons, calcite twins can be used as paleopressure gauges. Combined with fracture analysis, suture roughness and rock mechanics parameters, the differential paleostress method can be used to restore the evolution of paleofluid pressure. This method can only qualitatively analyze whether there is paleo-overpressure, and cannot quantitatively calculate the paleopressure values ​​of formations in different historical periods. (5) Other methods include estimating paleopressure using mineral veins, estimating the formation pressure of clay minerals based on the formation temperature and actual curves of clay minerals, and the tectonic stress method used to study the paleopressure of formations under tectonic compression. These methods are all based on certain assumptions and can only qualitatively estimate the size of paleopressure.

[0004] In summary, most of the existing reservoir paleopressure calculation methods have limitations and are only applicable to qualitative estimation or specific areas. The more reliable quantitative calculation methods, such as the laser Raman shift calculation of methane inclusions, require a large number of microscopic fluid inclusion observations and tests, but can only calculate the reservoir paleopressure value at the historical moment of inclusion filling. The paleopressure of other historical periods is based on the fitting and inference of the test points. Moreover, the above methods can only calculate the paleopressure value at one point in the reservoir well section, and cannot calculate the paleopressure evolution data of the entire well section. At present, there is still a lack of a quantitative calculation method for paleopressure of the entire well section that is highly applicable to clastic gas reservoirs and takes into account the historical time evolution. Summary of the invention

[0005] The main technical problem to be solved by the present invention is to provide a quantitative calculation method for paleopressure of the entire well section which has strong applicability to clastic gas reservoirs and takes into account the historical time evolution.

[0006] According to a first aspect of the present invention, the present invention provides a method for calculating the paleo-pressure of a clastic gas reservoir in the entire well section, comprising the following steps:

[0007] The basic physical property parameters of the clastic rock formation to be predicted are obtained by using the clastic rock reservoir physical property interpretation method; the basic physical property parameters include: the rock mud mineral content f of the clastic rock formation to be predicted sh , volume content of each mineral composition f i and present-day rock porosity φ0;

[0008] According to the volume content of each mineral composition f i , the rock matrix compressibility coefficient C of the rock sample is calculated using the Voigt-Reuss-Hill average modulus model s and rock matrix shear modulus μ s ;

[0009] Establish a functional relationship between the total volume of rock samples, rock skeleton compression coefficient, rock matrix compression coefficient, confining pressure and pore volume at any geological history time, which is the first expression;

[0010] V pt =aV·(C bct -C st )·P ct

[0011] According to the rock matrix compression coefficient C s and rock matrix shear modulus μ s , using Kuster- Model, establish the rock skeleton compression coefficient C of any geological history period bct The expression of is the second expression:

[0012]

[0013] Based on the ideal gas state equation, the reservoir paleopressure P at any geological time t is established. pt The calculation expression of is the third expression:

[0014]

[0015] According to the first expression, the second expression and the third expression, the reservoir paleopressure P at any geological history time t is calculated based on the logging data. pt The expression of is the fourth expression:

[0016]

[0017] Where P p0 , T0 and V p0 are the current measured formation pressure, temperature and pore volume of the reservoir, which are a priori values; T t V is the ground temperature at any geological time t; pt is the pore volume at any geological history time t, a is the integral constant; V is the total volume of the rock sample, a priori value, φ t is the porosity at any geological time t; C bct is the rock skeleton compression coefficient at any geological history time t; P ct is the confining pressure at any geological time t; C st is the matrix compression coefficient at any geological time t; assuming that there is only mechanical deformation without mineral chemical reaction during the stratum uplift, and its mineral composition does not change, then C st =C s ;

[0018] Obtain the confining pressure, ground temperature and porosity at any geological history time t, and calculate the reservoir paleopressure P at any geological history time t through the fourth expression based on the measured formation pressure, temperature and pore volume of the reservoir today pt .

[0019] Preferably, the step of using a clastic reservoir physical property interpretation method to obtain basic physical property parameters of the clastic rock formation to be predicted comprises:

[0020] Acquiring logging data of the clastic rock formation to be predicted, wherein the logging data includes sonic logging data, density logging data and neutron logging data;

[0021] Calculate the content of mud minerals in clastic rock formations sh , the calculation formula is as follows:

[0022]

[0023] In the formula, f sh is the content of rock argillaceous minerals, GCUR is the formation constant, and SH is the natural gamma ray intensity index of the target layer;

[0024] According to the content of rock argillaceous minerals sh , the macroscopic rock volume balance model is used to calculate the rock porosity φ and the volume content f of each mineral component in the clastic rock formation. i , the calculation formula is as follows:

[0025]

[0026] Where φ is the rock porosity, f i is the volume content of the i-th mineral, Δt f , Δt sh , Δt ima and Δt are respectively the fluid time difference value, the shale time difference value, the i-th mineral time difference value and the acoustic time difference value in the acoustic logging data; ρ f , sh , ima and ρ are respectively the density of fluid, the density of shale, the density of the i-th mineral and the density value in the density logging data; CNL f 、CNL sh 、CNL ima and CNL are the neutron values ​​of fluid, shale, the neutron value of the i-th mineral and the neutron value in the neutron logging data, respectively; where Δt, ρ and CNL are the logging data of acoustic logging, density logging and neutron logging, respectively, Δt f , Δt sh , Δt ima , f , sh , ima 、CNL f 、CNL sh and CNL ima is a priori value; i = 1, 2, 3, ..., n, where n is the number of mineral species in the clastic rock formation;

[0027] The rock porosity φ and the volume content of each mineral component f i , as the final interpretation result of the physical properties of the clastic rock formation.

[0028] Furthermore, the calculation formula of the natural gamma ray intensity index of the target layer is as follows:

[0029]

[0030] In the formula, GR max and GRmin are the maximum and minimum values ​​of the natural gamma curve, GR is the natural gamma reading of the mud-bearing target layer; GR max , GR min and GR are prior values.

[0031] Furthermore, the rock matrix compression coefficient C s and rock matrix shear modulus μ s The calculation formula is as follows:

[0032]

[0033] In the formula, C i is the compressibility coefficient of N mineral components in the rock, μ i is the equivalent shear modulus of N mineral components in the rock, the compressibility coefficient of the rock mineral component is a priori value, and i is an integer greater than or equal to 1

[0034] Furthermore, the step of establishing a functional relationship between the total volume of the rock sample, the rock skeleton compression coefficient, the rock matrix compression coefficient, the confining pressure and the pore volume at any geological history time includes:

[0035] The functional relationship between the compaction coefficient of rock formation and pore volume, pore volume change, and confining pressure change is obtained as the fifth expression:

[0036]

[0037] In the formula, C pc is the rock formation compaction coefficient, P -1 ; ΔP c is the change of confining pressure; V p is the pore volume; ΔV p is the change in pore volume;

[0038] The functional relationship between the rock formation compaction coefficient and the rock skeleton compression coefficient, rock matrix compression coefficient, and porosity is obtained as the sixth expression:

[0039]

[0040] In the formula, C bc is the rock skeleton compression coefficient, P -1 ; C s is the rock matrix compressibility coefficient, P -1 ; φ is the porosity;

[0041] According to the fifth expression and the sixth expression, a functional relationship between the rock skeleton compression coefficient, the rock matrix compression coefficient, the porosity, the confining pressure change, the pore volume and the pore volume change is established as the seventh expression:

[0042]

[0043] According to the definition of porosity φ=V p / V, where V is the total volume of the rock sample, and the functional relationship between the rock skeleton compression coefficient, rock matrix compression coefficient, total volume of the rock sample, confining pressure change and pore volume change is obtained as the eighth expression:

[0044] V(C bc -C s )·ΔP c =-ΔV p

[0045] Integrating both sides of the eighth expression yields the functional relationship between the total volume of the rock sample, the rock skeleton compression coefficient, the rock matrix compression coefficient, the confining pressure and the pore volume, which is the ninth expression:

[0046] V p =aV(C bc -C s )·P c ;

[0047] Then the functional relationship between the total volume of the rock sample, the rock skeleton compression coefficient, the rock matrix compression coefficient, the confining pressure and the pore volume at any geological history time t is the first expression:

[0048] V pt =aV·(C bct -C st )·P ct .

[0049] Preferably, the step of establishing a functional relationship between the total volume of the rock sample, the rock skeleton compression coefficient, the rock matrix compression coefficient, the confining pressure and the pore volume at any geological history time also includes:

[0050] Get the integral constant a; the method for getting the integral constant a is:

[0051] Using the current confining pressure P c0 The rock skeleton compression coefficient C bc0 , pore volume V p0 , the total volume of the rock sample V and the rock matrix compressibility C s Substituting the discrete value into the first expression yields:

[0052] a=V p0 +V·(C bc0 -C s )·P c0 .

[0053] Preferably, the calculation formula for obtaining the confining pressure at any geological historical time t is as follows:

[0054] P ct =P c0 +ρ s (H t -H0)

[0055] Where P ct is the confining pressure at any geological time t, P c0 is the current formation confining pressure, which is a priori value; ρ s is the empirical value of shallow stratum density, which is a priori value; H t is the stratigraphic depth at any geological time t, obtained by simulating the burial history map according to the basin; H0 is the current stratigraphic depth, a priori value.

[0056] Preferably, the ground temperature at any geological historical time t is obtained by a specific method: obtaining it according to a basin thermal history simulation temperature-geological time evolution diagram.

[0057] Preferably, the step of obtaining the porosity at any geological historical time t comprises:

[0058] The porosity φ at any geological history time t is calculated based on the depth-porosity relationship index model. t :

[0059]

[0060] Where φ0 is the porosity at current normal pressure, a priori value; e is the base of the natural logarithm, a priori value; k is the compaction factor, a priori value; H t is the stratigraphic depth at any geological time t; H0 is the current stratigraphic depth, a priori value.

[0061] According to another aspect of the present invention, a device for calculating the paleo-pressure of a clastic gas reservoir in the entire well section is provided, comprising the following modules:

[0062] The basic physical property parameter acquisition module is used to obtain the basic physical property parameters of the clastic rock formation to be predicted by using the clastic rock reservoir physical property interpretation method; the basic physical property parameters include: the rock mud mineral content f of the clastic rock formation to be predicted sh , volume content of each mineral composition f i and present-day rock porosity φ0;

[0063] The matrix parameter calculation module is used to calculate the volume content of each mineral component f i , the rock matrix compressibility coefficient C of the rock sample is calculated using the Voigt-Reuss-Hill average modulus model s and rock matrix shear modulus μs ;

[0064] A first expression building module is used to build a functional relationship between the total volume of the rock sample, the rock skeleton compression coefficient, the rock matrix compression coefficient, the confining pressure and the pore volume at any geological history time, which is the first expression;

[0065] V pt =aV·(C bct -C st )·P ct

[0066] The second expression building module is used to calculate the rock matrix compression coefficient C according to the rock matrix compression coefficient C. s and rock matrix shear modulus μ s ,use Model, establish the rock skeleton compression coefficient C of any geological history period bct The expression of is the second expression:

[0067]

[0068] The third expression building module is used to establish the reservoir paleopressure P at any geological history time t based on the ideal gas state equation. pt The calculation expression of is the third expression:

[0069]

[0070] The fourth expression building module is used to calculate the reservoir paleopressure P at any geological history time t based on the logging data according to the first expression, the second expression and the third expression. pt The expression of is the fourth expression:

[0071]

[0072] Where P p0 , T0 and V p0 are the current measured formation pressure, temperature and pore volume of the reservoir, which are a priori values; T t V is the ground temperature at any geological time t; pt is the pore volume at any geological history time t, a is the integral constant; V is the total volume of the rock sample, a priori value, φ t is the porosity at any geological time t; C bct is the rock skeleton compression coefficient at any geological history time t; P ct is the confining pressure at any geological time t; C stis the matrix compression coefficient at any geological time t; assuming that there is only mechanical deformation without mineral chemical reaction during the stratum uplift, and its mineral composition does not change, then C st =C s ;

[0073] The reservoir paleopressure calculation module is used to obtain the confining pressure, ground temperature and porosity at any geological history time t, and calculate the reservoir paleopressure P at any geological history time t through the fourth expression based on the current measured formation pressure, temperature and pore volume of the reservoir pt .

[0074] The technical solution provided by the present invention has the following beneficial effects:

[0075] In view of the difficulty of quantitatively calculating paleopressure that is generally applicable and continuous in gas reservoirs, the rock elastic parameter of rock skeleton compression coefficient is used as the key parameter of the model, and the quantitative relationship between the pore volume change of rock in each historical period and the rock skeleton compression coefficient and the overburden load is theoretically established; then the formation paleopressure value of each historical period is calculated in combination with the ideal gas state equation. This is a new method for calculating formation paleopressure, which does not require any experimental tests and can continuously calculate the paleopressure value of each historical time period in the entire well section. To a certain extent, it solves the problem that the previous paleopressure quantitative calculation method relies on microscopic fluid inclusion observation and testing, and it is difficult to continuously calculate the paleopressure of each geological historical period in the entire well section. It plays an important role in basin analysis and oil and gas reservoir dynamics research, and has important industrial application value in oil and gas exploration and evaluation. BRIEF DESCRIPTION OF THE DRAWINGS

[0076] The specific effects of the present invention will be further described below in conjunction with the accompanying drawings and embodiments, in which:

[0077] Figure 1 This is a flow chart of a method for calculating the reservoir paleopressure of a clastic gas reservoir in the entire well section based on well logging data according to an embodiment of the present invention;

[0078] Figure 2 This is a 3500m burial depth-geological time evolution diagram of a well in a dense clastic gas reservoir in a craton sedimentary basin according to an embodiment of the present invention;

[0079] Figure 3 This is a temperature-geological time evolution diagram of a well at 3500 m in a dense clastic gas reservoir in a craton sedimentary basin according to an embodiment of the present invention;

[0080] Figure 4 It is the result of well logging interpretation of the physical properties of a clastic reservoir in a well of a tight clastic gas reservoir in a craton sedimentary basin according to an embodiment of the present invention;

[0081] Figure 5The embodiment of the present invention calculates the paleopressure-geological age relationship diagram of a well in a dense clastic gas reservoir in a craton sedimentary basin;

[0082] Figure 6 The present invention is a structural diagram of a device for calculating the paleo-pressure of a clastic gas reservoir in the entire well section based on well logging data according to an embodiment of the present invention. DETAILED DESCRIPTION

[0083] In order to have a clearer understanding of the technical features, purposes and effects of the present invention, specific embodiments of the present invention are now described in detail with reference to the accompanying drawings.

[0084] Embodiment 1:

[0085] refer to Figure 1 This embodiment provides a method for calculating the paleo-pressure of the entire well section of a clastic gas reservoir based on well logging data, comprising the following steps:

[0086] S1: Using the clastic reservoir physical property interpretation method, the predicted clastic strata are calculated to obtain the basic physical property parameters of the predicted clastic strata; the basic physical property parameters include: the rock mud (clay) mineral content f of the predicted clastic strata sh , volume content of each mineral composition f i , present-day rock porosity φ0;

[0087] S1 specifically includes:

[0088] S11: Acquire logging data of the clastic rock formation to be predicted, wherein the logging data includes sonic logging data, density logging data and neutron logging data;

[0089] S12: Calculate the rock mud (clay) mineral content f in clastic rock formations sh , the calculation formula is as follows:

[0090]

[0091] In the formula, f sh is the rock mud (clay) mineral content, GCUR is the formation constant, SH is the natural gamma ray intensity index of the target layer, and the specific calculation formula is as follows:

[0092]

[0093] In the formula, GR max and GR min are the maximum and minimum values ​​of the natural gamma curve, GR is the natural gamma reading of the mud-bearing target layer; GR max , GR min and GR are prior values.

[0094] S13: According to the rock mud (clay) mineral content f sh , the macroscopic rock volume balance model is used to calculate the rock porosity φ and the volume content f of each mineral component in the clastic rock formation. i , the calculation formula is as follows:

[0095]

[0096] Where φ is the rock porosity, f i is the volume content of the i-th mineral, Δt f , Δt sh , Δt ima and Δt are respectively the fluid time difference value, the shale time difference value, the i-th mineral time difference value and the acoustic time difference value in the acoustic logging data; ρ f , sh , ima and ρ are respectively the density of fluid, the density of shale, the density of the i-th mineral and the density value in the density logging data; CNL f 、CNL sh 、CNL ima and CNL are the neutron values ​​of fluid, shale, the neutron value of the i-th mineral and the neutron value in the neutron logging data, respectively; where Δt, ρ and CNL are the logging data of acoustic logging, density logging and neutron logging, respectively, Δt f , Δt sh , Δt ima , f , sh , ima 、CNL f 、CNL sh and CNL ima is a priori value; i = 1, 2, 3, ..., n, where n is the number of mineral species in the clastic rock formation;

[0097] S14: rock porosity φ and volume content of each mineral component f i , as the final interpretation result of the physical properties of the clastic rock formation.

[0098] Preferably, in step S12, the value of the formation constant GCUR is 2.

[0099] Furthermore, in step S13, the calculation steps of the macro rock volume balance model are as follows:

[0100] S301: searching for an initial value close to the solution through a particle swarm algorithm;

[0101] S302: Based on the initial values, a nonlinear constrained optimization method is used to obtain an accurate solution for the rock porosity and the volume content of the i-th mineral, where i=1, 2, 3, ..., n, and n is the number of mineral types in the clastic rock formation.

[0102] S2: According to the volume content of each mineral composition f i , the rock matrix compressibility coefficient C of the rock sample is calculated using the Voigt-Reuss-Hill average modulus model s and rock matrix shear modulus μ s ; The calculation formula is as follows:

[0103]

[0104] In the formula, C i is the compressibility coefficient of N mineral components in the rock, μ i is the equivalent shear modulus of N mineral components in the rock, the compressibility coefficient of the rock mineral component is a priori value (Table 1), and i is an integer greater than or equal to 1.

[0105] Table 1 Empirical values ​​of compression coefficient of each mineral component

[0106]

[0107] S3: Establish the functional relationship between the total volume of the rock sample, the rock skeleton compression coefficient, the rock matrix compression coefficient, the confining pressure and the pore volume at any geological history time, which is the first expression;

[0108] V pt =aV·(C bct -C st )·P ct

[0109] S3 specifically includes:

[0110] S31: Obtain the functional relationship between the compaction coefficient of the rock formation and the pore volume, pore volume change, and confining pressure change, which is the fifth expression:

[0111]

[0112] In the formula, C pc is the rock formation compaction coefficient, P -1 ; ΔP c is the change of confining pressure; V p is the pore volume; ΔV p is the change in pore volume;

[0113] S32: Obtain the functional relationship between the rock formation compaction coefficient and the rock skeleton compression coefficient, rock matrix compression coefficient, and porosity, which is the sixth expression:

[0114]

[0115] In the formula, C bcis the rock skeleton compression coefficient, P -1 ; C s is the rock matrix compressibility coefficient, P -1 ; φ is the porosity;

[0116] S33: Based on the fifth expression and the sixth expression, a functional relationship between the rock skeleton compression coefficient, the rock matrix compression coefficient, the porosity, the confining pressure change, the pore volume and the pore volume change is established, which is the seventh expression:

[0117]

[0118] S34: According to the definition of porosity φ = V p / V, where V is the total volume of the rock sample, and the functional relationship between the rock skeleton compression coefficient, rock matrix compression coefficient, total volume of the rock sample, confining pressure change and pore volume change is obtained as the eighth expression:

[0119] V(C bc -C s )·ΔP c =-ΔV p

[0120] S35: Integrating both sides of the eighth expression yields the functional relationship between the total volume of the rock sample, the rock skeleton compression coefficient, the rock matrix compression coefficient, the confining pressure and the pore volume, which is the ninth expression:

[0121] V p =aV(C bc -C s )·P c ;

[0122] Then the functional relationship between the total volume of the rock sample, the rock skeleton compression coefficient, the rock matrix compression coefficient, the confining pressure and the pore volume at any geological history time t is the first expression:

[0123] V pt =aV·(C bct -C st )·P ct .

[0124] Optionally, in step S3, it further includes: obtaining an integral constant a;

[0125] The method to obtain the integral constant a is:

[0126] Using the current confining pressure P c0 The rock skeleton compression coefficient C bc0 , pore volume V p0 , the total volume of the rock sample V and the rock matrix compressibility C sSubstituting the discrete value into the first expression yields:

[0127] a=V p0 +V·(C bc0 -C s )·P c0 .

[0128] S4: According to the rock matrix compression coefficient C s and rock matrix shear modulus μ s , using Kuster- Model, establish the rock skeleton compression coefficient C of any geological history period bct The expression of is the second expression:

[0129]

[0130] S4 specifically includes:

[0131] Using Kuster- The model is used to obtain the expression of the rock skeleton compression coefficient of the clastic rock formation to be predicted:

[0132]

[0133] Where P m =3 / (4C s μ s )+1 is the effect after adding porosity to the background medium, u s is the rock matrix shear modulus, P. Extending the above formula to any geological history time t yields:

[0134]

[0135] In the formula, C bct is the rock skeleton compression coefficient at any geological history time t, φ t is the porosity at any geological time t. The above formula is transformed to obtain the formula for calculating the rock skeleton compression coefficient at any geological time t, which is the second expression:

[0136]

[0137] S5: Based on the ideal gas state equation, establish the reservoir paleopressure P at any geological history time t pt The calculation expression of is the third expression:

[0138]

[0139] S6: According to the first expression, the second expression and the third expression, the reservoir paleopressure P at any geological history time t is calculated based on the logging data.pt The expression of is the fourth expression:

[0140]

[0141] Where P p0 , T0 and V p0 are the current measured formation pressure, temperature and pore volume of the reservoir, which are a priori values; T t V is the ground temperature at any geological time t; pt is the pore volume at any geological history time t, a is the integral constant; V is the total volume of the rock sample, a priori value, φ t is the porosity at any geological time t; C bct is the rock skeleton compression coefficient at any geological history time t; P et is the confining pressure at any geological time t; C st is the matrix compression coefficient at any geological time t; assuming that there is only mechanical deformation without mineral chemical reaction during the stratum uplift, and its mineral composition does not change, then C st =C s .

[0142] S7: Obtain the confining pressure, ground temperature and porosity at any geological history time t, and calculate the reservoir paleopressure P at any geological history time t through the fourth expression based on the measured formation pressure, temperature and pore volume of the reservoir today. pt .

[0143] S7 specifically includes:

[0144] S71: Obtain the confining pressure at any geological historical time t, and the calculation formula is as follows:

[0145] P ct =P c0 +ρ s (H t -H0)

[0146] Where P ct is the confining pressure at any geological time t, P c0 is the current formation confining pressure, which is a priori value; ρ s is the empirical value of shallow stratum density, which is a priori value and is taken as 2.65 g / cm 3 ;H t is the stratigraphic depth at any geological time t, and is simulated according to the burial history diagram of the basin ( Figure 2 ) is obtained, for example, the current burial depth of sample YP02 is 3500m, and at t = 100Ma, the burial depth is H t is 4200m; H0 is the present stratum depth, a priori value.

[0147] S72: Obtain the ground temperature at any geological history time t. The specific acquisition method is: simulate the temperature-geological time evolution diagram based on the basin thermal history ( Figure 3 ) to obtain.

[0148] S73: Obtaining the porosity at any geological history time t, specifically including:

[0149] The porosity φ at any geological history time t is calculated based on the depth-porosity relationship index model. t :

[0150]

[0151] Where φ0 is the porosity at current normal pressure, a priori value; e is the base of the natural logarithm, a priori value; k is the compaction factor, a priori value; H t is the stratigraphic depth at any geological time t; H0 is the current stratigraphic depth, a priori value.

[0152] S74: Based on the results obtained by calculation in S71-S73, and based on the measured formation pressure, temperature and pore volume of the reservoir today, the reservoir paleopressure P at any geological history time t is calculated by the fourth expression: pt .

[0153] Using the above method of the embodiment of the present invention, firstly, the clastic reservoir physical property interpretation method is used to carry out calculations to obtain the basic physical property parameters of the clastic rock formation to be predicted. The calculation results are as follows: Figure 4 Based on the results of these physical parameters, the rock matrix compression coefficient C of the entire well section is calculated. s and the rock matrix shear modulus u s , three present-day depth points were selected: 3300m, 3400m, and 3500m (with paleopressure values ​​restored by laser Raman shift of methane inclusions) to carry out paleopressure calculations.

[0154] The calculated results are as follows Figure 5 As shown, the paleopressure value ( Figure 5 The lines in the figure) and the paleopressure value restored by laser Raman shift of methane inclusions ( Figure 5 Therefore, the method of this embodiment can accurately calculate the ancient pressure value of gas reservoirs at any present depth, has stronger applicability and practicality than previous methods, and can continuously calculate the ancient pressure values ​​of various historical periods, and has certain industrial application value.

[0155] Based on the definitions of rock formation compaction coefficient and rock skeleton compression coefficient, this embodiment derives and establishes a theoretical formula for characterizing the change of pore volume during geological history. Physical parameter data such as rock mineral composition and porosity data are calculated using logging data. The rock skeleton compression coefficient values ​​of each geological history period are calculated through a variety of rock physics models, and then the change of pore volume in each historical period is obtained. When the reservoir is a dry gas or wet gas reservoir (the temperature of the gas reservoir is always higher than the fluid phase envelope zone, and there is no phase change process), based on the ideal gas state equation, the current measured reservoir pressure and temperature are used as the starting point, combined with the simulated formation thermal evolution history paleotemperature curve, and then the reservoir paleopressure value of each historical period is calculated.

[0156] This embodiment aims at the current difficult problem of universal applicability and continuous paleopressure quantitative calculation of clastic gas reservoirs, and proposes a method for calculating the paleopressure of the entire well section of the reservoir in the clastic gas reservoir using logging data. To a certain extent, it solves the problem that the previous paleopressure quantitative calculation methods rely on microscopic fluid inclusion observations and tests, and it is difficult to continuously calculate the paleopressure of each geological historical period in the entire well section. By comparing the calculated paleopressure value with the paleopressure value restored by laser Raman shift of methane inclusions, it can be seen that this method can accurately calculate the paleopressure value of the gas reservoir, has stronger applicability and practicality than previous methods, and can continuously calculate the paleopressure value of each historical period in the entire well section, and has certain industrial application value.

[0157] Embodiment 2:

[0158] refer to Figure 6 This embodiment provides a device for calculating the reservoir paleopressure of a clastic gas reservoir in the entire well section based on well logging data, comprising the following modules:

[0159] The basic physical property parameter acquisition module 1 is used to obtain the basic physical property parameters of the clastic rock formation to be predicted by using the clastic rock reservoir physical property interpretation method; the basic physical property parameters include: the rock mud (clay) mineral content f of the clastic rock formation to be predicted sh , volume content of each mineral composition f i and present-day rock porosity φ0;

[0160] Matrix parameter calculation module 2 is used to calculate the volume content of each mineral component f i , the rock matrix compressibility coefficient C of the rock sample is calculated using the Voigt-Reuss-Hill average modulus model s and rock matrix shear modulus μ s ;

[0161] The first expression establishment module 3 is used to establish a functional relationship between the total volume of the rock sample, the rock skeleton compression coefficient, the rock matrix compression coefficient, the confining pressure and the pore volume at any geological history time, which is the first expression;

[0162] V pt =aV·(C bct -C st )·P ct

[0163] The second expression building module 4 is used to calculate the rock matrix compression coefficient C according to the rock matrix compression coefficient C. s and rock matrix shear modulus μ s ,use Model, establish the rock skeleton compression coefficient C of any geological history period bct The expression of is the second expression:

[0164]

[0165] The third expression building module 5 is used to establish the reservoir paleopressure P at any geological history time t based on the ideal gas state equation. pt The calculation expression of is the third expression:

[0166]

[0167] The fourth expression building module 6 is used to calculate the reservoir paleopressure P at any geological history time t based on the logging data according to the first expression, the second expression and the third expression. pt The expression of is the fourth expression:

[0168]

[0169] Where P p0 , T0 and V p0 are the current measured formation pressure, temperature and pore volume of the reservoir, which are a priori values; T t V is the ground temperature at any geological time t; pt is the pore volume at any geological history time t, a is the integral constant; V is the total volume of the rock sample, a priori value, φ t is the porosity at any geological time t; C bct is the rock skeleton compression coefficient at any geological history time t; P ct is the confining pressure at any geological time t; C st is the matrix compression coefficient at any geological time t; assuming that there is only mechanical deformation without mineral chemical reaction during the stratum uplift, and its mineral composition does not change, then C st =C s ;

[0170] The reservoir paleopressure calculation module 7 is used to obtain the confining pressure, ground temperature and porosity at any geological history time t, and calculate the reservoir paleopressure P at any geological history time t through the fourth expression based on the measured formation pressure, temperature and pore volume of the reservoir today. pt .

[0171] The above-mentioned device for calculating the paleo-pressure of the reservoir in the entire well section of the clastic gas reservoir is used to implement each process of the embodiment of the method for calculating the paleo-pressure of the reservoir in the clastic gas reservoir described in the first embodiment, and can achieve the same technical effect.

[0172] It should be noted that, in this article, the terms "include", "comprises" or any other variations thereof are intended to cover non-exclusive inclusion, so that a process, method, article or system including a series of elements includes not only those elements, but also other elements not explicitly listed, or also includes elements inherent to such process, method, article or system. In the absence of further restrictions, an element defined by the sentence "comprises a ..." does not exclude the existence of other identical elements in the process, method, article or system including the element.

[0173] The serial numbers of the embodiments of the present invention are for descriptive purposes only and do not represent the superiority or inferiority of the embodiments. In a unit claim that lists several means, several of these means may be embodied by the same hardware item. The use of the words first, second, and third, etc. does not indicate any order and these words may be interpreted as identifiers.

[0174] The above are only preferred embodiments of the present invention, and are not intended to limit the patent scope of the present invention. Any equivalent structure or equivalent process transformation made using the contents of the present invention specification and drawings, or directly or indirectly applied in other related technical fields, are also included in the patent protection scope of the present invention.

Claims

1. A method for calculating the paleo-pressure of the entire well section of a clastic gas reservoir, characterized in that: The following steps are involved: The basic physical property parameters of the clastic rock formation to be predicted are obtained by using the clastic rock reservoir physical property interpretation method; The basic physical property parameters include: the rock shale mineral content f of the clastic rock formation to be predicted sh , volume content of each mineral composition f i and present-day rock porosity φ0; According to the volume content of each mineral composition f i , the rock matrix compressibility coefficient C of the rock sample is calculated using the Voigt-Reuss-Hill average modulus model s and rock matrix shear modulus μ s ; Establish a functional relationship between the total volume of rock samples, rock skeleton compression coefficient, rock matrix compression coefficient, confining pressure and pore volume at any geological history time, which is the first expression; In pt =aV·(C bct -C st )·P ct According to the rock matrix compression coefficient C s and rock matrix shear modulus μ s , using Kuster- Model, establish the rock skeleton compression coefficient C of any geological history period bat The expression of is the second expression: Based on the ideal gas state equation, the reservoir paleopressure P at any geological time t is established. pt The calculation expression of is the third expression: According to the first expression, the second expression and the third expression, the reservoir paleopressure P at any geological history time t is calculated based on the logging data. pt The expression of is the fourth expression: Where P p0 , T0 and V p0 are the current measured formation pressure, temperature and pore volume of the reservoir, which are a priori values; T t V is the ground temperature at any geological time t; pt is the pore volume at any geological history time t, a is the integral constant; V is the total volume of the rock sample, a priori value, φ t is the porosity at any geological time t; C bct is the rock skeleton compression coefficient at any geological history time t; P ct is the confining pressure at any geological time t; C st is the matrix compression coefficient at any geological time t; assuming that there is only mechanical deformation without mineral chemical reaction during the stratum uplift, and its mineral composition does not change, then C st =C s ; Obtain the confining pressure, ground temperature and porosity at any geological history time t, and calculate the reservoir paleopressure P at any geological history time t through the fourth expression based on the measured formation pressure, temperature and pore volume of the current reservoir pt .

2. A method for calculating the paleo-pressure of a clastic gas reservoir in the entire well section as claimed in claim 1, characterized in that: The step of using the clastic reservoir physical property interpretation method to obtain the basic physical property parameters of the clastic rock formation to be predicted includes: Acquiring logging data of the clastic rock formation to be predicted, wherein the logging data includes sonic logging data, density logging data and neutron logging data; Calculate the content of mud minerals in clastic rock formations sh , the calculation formula is as follows: In the formula, f sh is the content of rock argillaceous minerals, GCUR is the formation constant, and SH is the natural gamma ray intensity index of the target layer; According to the content of rock argillaceous minerals sh , the macroscopic rock volume balance model is used to calculate the rock porosity φ and the volume content f of each mineral component in the clastic rock formation. i , the calculation formula is as follows: Where φ is the rock porosity, f i is the volume content of the i-th mineral, Δt f , Δt sh , Δt ima and Δt are respectively the fluid time difference value, the shale time difference value, the i-th mineral time difference value and the acoustic time difference value in the acoustic logging data; ρ f , sh , ima and ρ are respectively the density of fluid, the density of shale, the density of the i-th mineral and the density value in the density logging data; CNL f 、CNL sh 、CNL ima and CNL are the neutron values ​​of fluid, shale, the neutron value of the i-th mineral and the neutron value in the neutron logging data, respectively; where Δt, ρ and CNL are the logging data of acoustic logging, density logging and neutron logging, respectively, Δt f , Δt sh , Δt ima , f , sh , ima 、CNL f 、CNL sh and CNL ima is a priori value; i = 1, 2, 3, ..., n, n is the number of mineral species in the clastic rock formation; The rock porosity φ and the volume content of each mineral component f i , as the final interpretation result of the physical properties of the clastic rock formation.

3. A method for calculating the paleo-pressure of a clastic gas reservoir in the entire well section as claimed in claim 2, characterized in that: The calculation formula of the natural gamma ray intensity index of the target layer is as follows: In the formula, GR max and GR min are the maximum and minimum values ​​of the natural gamma curve, GR is the natural gamma reading of the mud-bearing target layer; GR max , GR min and GR are prior values.

4. The method for calculating the paleo-pressure of the entire well section of a clastic gas reservoir according to claim 1, characterized in that: The rock matrix compressibility coefficient C s and rock matrix shear modulus μ s The calculation formula is as follows: In the formula, C i is the compressibility coefficient of N mineral components in the rock, μ i is the equivalent shear modulus of N mineral components in the rock, the compression coefficient of the rock mineral component is a priori value, and i is an integer greater than or equal to 1.

5. The method for calculating the paleo-pressure of the entire well section of a clastic gas reservoir according to claim 1, characterized in that: The step of establishing a functional relationship between the total volume of the rock sample, the rock skeleton compression coefficient, the rock matrix compression coefficient, the confining pressure and the pore volume at any geological history time includes: The functional relationship between the compaction coefficient of rock formation and pore volume, pore volume change, and confining pressure change is obtained as the fifth expression: In the formula, C pc is the rock formation compaction coefficient, P -1 ; ΔP c is the change of confining pressure; V p is the pore volume; ΔV p is the change in pore volume; The functional relationship between the rock formation compaction coefficient and the rock skeleton compression coefficient, rock matrix compression coefficient, and porosity is obtained as the sixth expression: In the formula, C bc is the rock skeleton compression coefficient, P -1 ; C s is the rock matrix compressibility coefficient, P -1 ; φ is the porosity; According to the fifth expression and the sixth expression, a functional relationship between the rock skeleton compression coefficient, the rock matrix compression coefficient, the porosity, the confining pressure change, the pore volume and the pore volume change is established as the seventh expression: According to the definition of porosity φ=V p / V, where V is the total volume of the rock sample, and the functional relationship between the rock skeleton compression coefficient, rock matrix compression coefficient, total volume of the rock sample, confining pressure change and pore volume change is obtained as the eighth expression: V(C bc -C s )·ΔP c =-ΔV p Integrating both sides of the eighth expression yields the functional relationship between the total volume of the rock sample, the rock skeleton compression coefficient, the rock matrix compression coefficient, the confining pressure and the pore volume, which is the ninth expression: In p =aV(C bc -C s )·P c ; Then the functional relationship between the total volume of the rock sample, the rock skeleton compression coefficient, the rock matrix compression coefficient, the confining pressure and the pore volume at any geological history time t is the first expression: In pt =aV·(C bct -C st )·P ct 。 6. A method for calculating paleo-pressure of a clastic gas reservoir in the entire well section as claimed in claim 5, characterized in that: The step of establishing a functional relationship between the total volume of the rock sample, the rock skeleton compression coefficient, the rock matrix compression coefficient, the confining pressure and the pore volume at any geological history time also includes: Get the integral constant a; the method for getting the integral constant a is: Using the current confining pressure P c0 The rock skeleton compression coefficient C bc0 , pore volume V p0 , the total volume of the rock sample V and the rock matrix compressibility C s Substituting the discrete value into the first expression yields: a=V p0 +V·(C bc0 -C s )·P c0 。 7. The method for calculating the paleo-pressure of the entire well section of a clastic gas reservoir according to claim 1, characterized in that: The calculation formula for obtaining the confining pressure at any geological historical time t is as follows: P ct =P c0 +ρ s (H t -H0) Where P ct is the confining pressure at any geological time t, P c0 is the current formation confining pressure, which is a priori value; ρ s is the empirical value of shallow stratum density, which is a priori value; H t is the stratigraphic depth at any geological time t, obtained by simulating the burial history map according to the basin; H0 is the current stratigraphic depth, a priori value.

8. The method for calculating the paleo-pressure of the entire well section of a clastic gas reservoir according to claim 1, characterized in that: The ground temperature at any geological historical time t is obtained by a specific method: obtaining it according to a basin thermal history simulation temperature-geological time evolution diagram.

9. The method for calculating the paleo-pressure of the entire well section of a clastic gas reservoir according to claim 1, characterized in that: The step of obtaining the porosity at any geological history time t comprises: The porosity φ at any geological history time t is calculated based on the depth-porosity relationship index model. t : Where φ0 is the porosity under current normal pressure, a priori value; e is the base of the natural logarithm, a priori value; k is the compaction factor, a priori value; H t is the stratigraphic depth at any geological time t; H0 is the current stratigraphic depth, a priori value.

10. A device for calculating the paleo-pressure of the entire well section of a clastic gas reservoir, characterized in that: Includes the following modules: A basic physical property parameter acquisition module is used to obtain basic physical property parameters of the clastic rock formation to be predicted by adopting a clastic rock reservoir physical property interpretation method; The basic physical property parameters include: the rock shale mineral content f of the clastic rock formation to be predicted sh , volume content of each mineral composition f i and present-day rock porosity φ0; The matrix parameter calculation module is used to calculate the volume content of each mineral component f i , the rock matrix compressibility coefficient C of the rock sample is calculated using the Voigt-Reuss-Hill average modulus model s and rock matrix shear modulus μ s ; A first expression building module is used to build a functional relationship between the total volume of the rock sample, the rock skeleton compression coefficient, the rock matrix compression coefficient, the confining pressure and the pore volume at any geological history time, which is the first expression; In pt =aV·(C bct -C st )·P ct The second expression building module is used to calculate the rock matrix compression coefficient C according to the rock matrix compression coefficient C. s and rock matrix shear modulus μ s ,use Model, establish the rock skeleton compression coefficient C of any geological history period bct The expression of is the second expression: The third expression building module is used to establish the reservoir paleopressure P at any geological history time t based on the ideal gas state equation. pt The calculation expression of is the third expression: The fourth expression building module is used to calculate the reservoir paleopressure P at any geological history time t based on the logging data according to the first expression, the second expression and the third expression. pt The expression of is the fourth expression: Where P p0 , T0 and V p0 are the current measured formation pressure, temperature and pore volume of the reservoir, which are a priori values; T t V is the ground temperature at any geological time t; pt is the pore volume at any geological history time t, a is the integral constant; V is the total volume of the rock sample, a priori value, φ t is the porosity at any geological time t; C bct is the rock skeleton compression coefficient at any geological history time t; P ct is the confining pressure at any geological time t; C st is the matrix compression coefficient at any geological time t; assuming that there is only mechanical deformation without mineral chemical reaction during the stratum uplift, and its mineral composition does not change, then C st =C s ; The reservoir paleopressure calculation module is used to obtain the confining pressure, ground temperature and porosity at any geological history time t, and calculate the reservoir paleopressure P at any geological history time t through the fourth expression based on the current measured formation pressure, temperature and pore volume of the reservoir pt .

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