Quantitative Calculation Method for the Genesis of Abnormal Low Pressure in Clastic Gas Reservoirs

Abstract

This invention provides a quantitative calculation method for the causes of abnormal low pressure in clastic gas reservoirs, comprising: based on the formation compaction coefficient, overlying strata pressure, formation pressure, temperature, and natural gas compressibility factor at time t and t=0 during formation uplift; formation temperature, overlying strata pressure, formation pressure, water saturation, and natural gas compressibility factor before uplift; formation hydrothermal expansion coefficient, formation water compressibility coefficient, surface pressure, surface temperature, natural gas density under standard conditions, formation water density, and natural gas solubility in water; the residual coefficient of natural gas after dissipation; a formula for calculating the natural gas compressibility factor; a calculation formula for the formation pressure value after uplift time t; and based on the calculation formula, a controlled variable method is used to quantitatively calculate the relative contribution of various main controlling factors to the formation of the current abnormal low pressure. The method provided by this invention has wider applicability and greater practicality than previous methods.

Description

Technical Field

[0001] This invention relates to the field of geological exploration technology, and in particular to a quantitative calculation method for the cause of abnormal low pressure in clastic gas reservoirs. Background Technology

[0002] The analysis of the genesis of anomalous formation pressure in sedimentary basins is an important part of basin analysis and hydrocarbon accumulation dynamics research, playing a crucial role in oil and gas geological research and exploration. Anomalous low pressure, as an important type of pressure, is controlled by multiple factors, and its formation and evolution are closely related to hydrocarbon generation, migration, and accumulation. Different scholars, both domestically and internationally, have categorized the main controlling factors for the formation of anomalous low pressure in natural gas reservoirs into the following main types: ① porosity rebound caused by erosion and unloading of the overlying strata; ② decrease in formation temperature; ③ porosity enhancement due to dissolution; ④ other factors such as natural gas loss, pressure surfaces below the surface, and fluid density differences.

[0003] How to quantitatively characterize the contribution of the main controlling factors to the current abnormal low pressure? Several qualitative-semi-quantitative evaluation methods have been developed, mainly including the following categories: (1) The influence of pore rebound on formation pressure. The difference between the compressibility coefficients of reservoir rocks and reservoir fluids is used to quantitatively calculate the pressure drop caused by pore rebound due to pressure relief of overlying strata. This method requires estimating the erosion thickness and average density during the formation uplift process. The rock compressibility coefficient is often based on laboratory experience values. There is a lack of measured data in the study area, and it cannot accurately calculate the formation pressure drop of a single well; (2) The influence of temperature reduction on formation pressure. The difference between the expansion coefficients of formation water and rocks is used to quantitatively characterize the influence of pore rebound on formation pressure. The verification value is estimated by summing the changes in rock and fluid volume per unit volume, and then by combining Pascal's law to estimate the pressure drop caused by the decrease in formation temperature. This method is applicable to oil reservoirs but not to natural gas reservoirs. (3) The effect of dissolution and porosimetry on formation pressure is estimated by using the water-consuming chemical reaction equation of feldspar dissolution in the reservoir and combining the feldspar mineral content in the study area to qualitatively estimate the pressure drop caused by dissolution. This method is a qualitative estimate of the effect of dissolution from a theoretical perspective. (4) The contribution of other factors such as natural gas diffusion to the reduction of formation pressure is calculated by subtracting the pressure drop caused by other main controlling factors from the total formation pressure drop.

[0004] Currently, among the existing quantitative evaluation methods for the genesis of abnormal low pressure in reservoirs, the evaluation methods for different controlling factors are independent of each other, and the evaluation results are mostly qualitative to semi-quantitative estimates, often applicable to single-phase fluid types. There is currently a lack of a quantitative evaluation method for the genesis of abnormal low pressure in gas-water two-phase fluid clastic natural gas reservoirs.

[0005] Therefore, how to avoid the narrow application scope of traditional quantitative calculation of the causes of abnormal low pressure and the inconvenience of the lack of mutual coupling between the calculation of multiple factors remains a problem that needs to be solved by those skilled in the art. Summary of the Invention

[0006] This invention provides a quantitative calculation method for the genesis of abnormal low pressure in clastic gas reservoirs, which solves the problems of narrow application scope and lack of mutual coupling between the calculation of multiple factors in traditional quantitative calculation of abnormal low pressure genesis.

[0007] This invention provides a quantitative calculation method for the abnormal low-pressure origin of clastic gas reservoirs, including:

[0008] Step S110: Based on the formation compaction coefficient, overlying strata pressure, formation pressure, temperature, and natural gas compressibility factor at time t during the formation uplift process; the formation compaction coefficient, overlying strata pressure, formation pressure, temperature, and natural gas compressibility factor at geological history time t=0; the formation temperature, overlying strata pressure, formation pressure, water saturation, and natural gas compressibility factor before formation uplift; the formation hydrothermal expansion coefficient, formation water compressibility coefficient, surface pressure, surface temperature, natural gas density under standard conditions, formation water density, and natural gas solubility in water; and the residual coefficient of natural gas after dissipation, which are the coefficients in the natural gas compressibility factor calculation formula, calculate the pressure value P of the formation after uplift time t. Pt The calculation formula;

[0009] Step S120: Based on the pressure value P Pt The calculation formula uses the controlled variable method to quantitatively calculate the influence of multiple controlling factors during the tectonic uplift period on the current abnormally low pressure P. Pt The relative contribution of the formation is determined by various controlling factors, including uplift erosion, temperature reduction, natural gas loss, and dissolution-induced porosity.

[0010] According to the quantitative calculation method for the abnormal low pressure genesis of clastic gas reservoirs provided by the present invention, step S110 specifically includes:

[0011] Step S1: At any geological time t during the tectonic uplift process, the change in rock pore volume due to the decrease in overlying strata pressure is as follows:

[0012] V pt =V p1 (1-C pct ·Δσ efft ) Formula 1

[0013] In Formula 1, V p1 and V pt These represent the rock pore volumes before and after tectonic uplift, C pct and Δσ efft The changes in compaction coefficient and effective stress of the rock formation, respectively;

[0014] Step S2: Under relatively semi-closed strata conditions, due to the decrease in strata temperature and pressure caused by tectonic uplift, the volume of formation water and natural gas in the rock pores changes as follows:

[0015] V wt =V p1 ·S w1 [1+α w (T t -T1)]·[1-β w (P pt -P p1 )] Formula 2

[0016]

[0017] In formulas 2 and 3, V wt V gt T t P pt m gt and Z t These represent the volume of formation water in the formation rock pores, the volume of natural gas, the formation temperature, the formation pressure, the mass of natural gas, and the natural gas compressibility factor at time t during the uplift process; V p1 S w1 T1 and P p1 These represent the pore volume, water saturation, formation temperature, and formation pressure before tectonic uplift, all of which are prior values; α w β w P p0 T0 and ρ g These are the thermal expansion coefficient of formation water, the compressibility coefficient of formation water, the pressure at the surface, the temperature at the surface, and the density of natural gas under standard conditions, all of which are a priori values.

[0018] Step S3: Under in-situ formation conditions, the natural gas stored in the pores undergoes dissolution by formation water and a certain degree of diffusion, resulting in a natural gas mass m. gt It becomes:

[0019]

[0020] In Formula 4, V p1 T1, P p1 Z1 and S w1 These represent the rock pore volume, formation temperature, formation pressure, natural gas compressibility factor, and water saturation before formation uplift; m g2 P p0 、T0、ρ g ρ w and S gwThe following parameters were constructed: the mass of natural gas after uplift, the pressure at the surface, the temperature at the surface, the density of natural gas under standard conditions, the density of formation water, and the solubility of natural gas in water; k is the residual coefficient of natural gas after dissipation.

[0021] Step S4: For natural gas reservoirs, the rock pores are always filled with gas-water two-phase fluid during the formation uplift process. Therefore, the volume of formation pores is always equal to the volume of fluid, hence the following relationship exists:

[0022] V pt =V wt +V gt Formula 5

[0023] In the formula, V pt V wt and V gt These represent the pore volume, formation water volume in the pores, and natural gas volume in the pores at time t after formation uplift, respectively.

[0024] Step S5: Change in effective stress Δσ efft The effective stress of the formation is obtained according to the following formula 6:

[0025] Δσ efft =(P rt -P Pt )-(P r1 -P P1 ) Formula 6

[0026] In the formula, P Pt and P rt P represents the formation pressure at time t during the formation uplift process and the pressure of the overlying strata, respectively; these are prior values. P1 To determine the formation pressure prior to uplift, the pressure is obtained by measuring fluid inclusion trapping pressure or basin simulation methods; this is a priori value. r1 The pressure of the overlying strata before tectonic uplift is a priori value.

[0027] Step S6: Combine equations 1-6 to obtain the theoretical equations relating the rock formation compaction coefficient, the change in effective stress, and formation temperature and pressure:

[0028]

[0029] In the formula, P pt T t and Z t These represent the formation pressure, temperature, and natural gas compressibility factor at time t during the tectonic uplift process; when the geological history time t is 0, these are all prior values; C pct , Δσ efft These represent the changes in the compaction coefficient and effective stress of the rock formation at time t during tectonic uplift; Vp1 T1, P p1 S w1 Z1 and Z2 represent the rock pore volume, formation temperature, formation pressure, water saturation, and natural gas compressibility factor before formation uplift, respectively; α w β w P p0 、T0、ρ g ρ w and S gw Here, represents the thermal expansion coefficient of formation water, the compressibility coefficient of formation water, the pressure at the surface, the temperature at the surface, the density of natural gas under standard conditions, the density of formation water, and the solubility of natural gas in water; k represents the residual coefficient of natural gas after dissipation.

[0030] Step S7: Solve the theoretical equation Formula 7, and based on the actual physical meaning of the relevant parameters, after eliminating invalid solutions to the equation, solve for the formation pressure value P at time t after uplift. Pt :

[0031] A·P Pt 2 +B·P Pt +C=0

[0032]

[0033] Where A = -β w ·S w [1+α w (T t -T1)]-C pct

[0034]

[0035]

[0036] According to the quantitative calculation method for the abnormal low pressure genesis of clastic gas reservoirs provided by the present invention, before step S1, the method further includes:

[0037] Test rocks under different effective stresses σ eff Pore ​​volume and rock compaction coefficient of the lower sandstone, fitting the rock pore volume and effective stress σ eff ;

[0038] Based on the rock pore volume and effective stress σ of different rock samples eff The power-law fitting formula is used to obtain the relationship between rock porosity φ and formation compaction coefficient C. pc The fitting relationship.

[0039] The present invention provides a quantitative calculation method for the abnormal low pressure of clastic gas reservoirs, based on rock porosity φ and formation compaction coefficient C.pc The fitting relationship is used to obtain the compaction coefficient and porosity of the rock formation and convert them into values ​​at time t during the uplift process.

[0040] According to the present invention, a quantitative calculation method for the abnormal low pressure of clastic gas reservoirs is provided, which tests the rocks under different effective stresses σ. eff The method for determining the pore volume and compaction coefficient of the underlying sandstone formation is to use a PoroPDP-200 overburden pressure permeability meter to test the compaction coefficient and pore volume of the formation using the helium method.

[0041] According to the quantitative calculation method for the abnormal low pressure of clastic gas reservoirs provided by the present invention, the compressibility factor Z of natural gas is calculated by fitting a Standing chart to the relationship between temperature and pressure.

[0042] According to the present invention, a quantitative calculation method for the abnormal low pressure of clastic gas reservoirs is provided, wherein the formation hydrothermal expansion coefficient α is... w Formation water compressibility coefficient β w Surface pressure P p0 Surface temperature T0, density of natural gas under standard conditions ρ g Density ρ of formation water w The solubility of natural gas in water (S) gw Critical temperature T of natural gas c All values ​​are based on laboratory test experience.

[0043] According to the present invention, a quantitative calculation method for the abnormal low pressure of clastic gas reservoirs is provided, wherein the porosity φ at time t during the uplift process is... t An approximate calculation was performed using the current depth-sonic transit time-measured porosity relationship exponential model, which correlates time t with formation depth H during the uplift process. t The functional relationship was obtained from the basin's simulated burial history map, and the overlying strata pressure P at time t during the tectonic uplift process was... rt Calculated according to a preset formula.

[0044] According to the present invention, a quantitative calculation method for the abnormal low pressure of clastic gas reservoirs is provided, wherein the formation temperature T at time t during the uplift process is... t The formation temperature T1 before uplift was obtained based on the temperature-geological time evolution diagram of the basin thermal history simulation.

[0045] The present invention provides a quantitative calculation method for the cause of abnormal low pressure in clastic gas reservoirs, which further includes: quantitatively calculating the contribution value of each main controlling factor to the low pressure through step S120, which requires obtaining the key parameter values ​​of reservoir rock porosity, formation temperature and pressure before and after the formation tectonic uplift.

[0046] The present invention provides a quantitative calculation method for the abnormal low pressure of clastic gas reservoirs. This method uses the following parameters to calculate the pressure value P of the formation after uplift time t: formation compaction coefficient, overlying strata pressure, formation pressure, temperature, and natural gas compressibility factor at time t during formation uplift; formation compaction coefficient, overlying strata pressure, formation pressure, temperature, and natural gas compressibility factor at geological time t=0; formation temperature, overlying strata pressure, formation pressure, water saturation, and natural gas compressibility factor before uplift; formation hydrothermal expansion coefficient, formation water compressibility factor, surface pressure, surface temperature, natural gas density under standard conditions, formation water density, and natural gas solubility in water; and the residual coefficient of natural gas after dissipation. These parameters are used as the coefficients in the natural gas compressibility factor calculation formula. Pt The calculation formula is based on the pressure value P. Pt The calculation formula uses the controlled variable method to quantitatively calculate the influence of multiple controlling factors during the tectonic uplift period on the current abnormally low pressure P. Pt The relative contribution of the resulting formation is determined by various controlling factors, including uplift erosion, temperature reduction, natural gas loss, and dissolution-induced porosity. The method provided by this invention has wider applicability and greater practicality than previous methods, and possesses certain industrial application value. Attached Figure Description

[0047] To more clearly illustrate the technical solutions in this invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are some embodiments of this invention. For those skilled in the art, other drawings can be obtained from these drawings without creative effort.

[0048] Figure 1 A flowchart illustrating the quantitative calculation method for the abnormal low pressure genesis of clastic gas reservoirs provided by this invention.

[0049] Figure 2 A schematic diagram illustrating the change in rock pore volume of a clastic rock sample as effective stress increases, provided by the present invention.

[0050] Figure 3 A schematic diagram illustrating the change of the formation compaction coefficient of clastic rock samples as effective stress increases, provided by the present invention.

[0051] Figure 4 This is a schematic diagram showing the change of rock pore volume with increasing effective stress under an effective stress of 55 MPa, provided by the present invention.

[0052] Figure 5 This invention provides a burial depth-geological time evolution diagram of clastic rocks at a depth of 3500m in a single well within a cratonic sedimentary basin.

[0053] Figure 6 Temperature-geological-time evolution diagram of clastic rocks at 3500m in a single well in a craton sedimentary basin provided by this invention;

[0054] Figure 7 This is a schematic diagram illustrating the relative contribution of the main controlling factors in evaluating the cause of abnormal low pressure in a single well, as provided by the present invention. Detailed Implementation

[0055] To make the objectives, technical solutions, and advantages of this invention clearer, the technical solutions of this invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some, not all, of the embodiments of this invention. All other embodiments obtained by those skilled in the art based on the embodiments of this invention without creative effort are within the scope of protection of this invention.

[0056] Existing quantitative calculation methods for the genesis of abnormally low pressure in clastic gas reservoirs generally suffer from narrow application scope and a lack of coupling between calculations of multiple factors. The following section will discuss... Figure 1 This invention describes a quantitative calculation method for the causes of abnormally low pressure in clastic gas reservoirs. Figure 1 This is a flowchart illustrating the quantitative calculation method for the abnormal low-pressure genesis of clastic gas reservoirs provided by the present invention, as shown below. Figure 1 As shown, the method includes:

[0057] Step 110: Based on the formation compaction coefficient, overlying strata pressure, formation pressure, temperature, and natural gas compressibility factor at time t during the formation uplift process; the formation compaction coefficient, overlying strata pressure, formation pressure, temperature, and natural gas compressibility factor at geological history time t=0; the formation temperature, overlying strata pressure, formation pressure, water saturation, and natural gas compressibility factor before formation uplift; the formation hydrothermal expansion coefficient, formation water compressibility coefficient, surface pressure, surface temperature, natural gas density under standard conditions, formation water density, and natural gas solubility in water; and the residual coefficient of natural gas after dissipation, which are used as the coefficients in the natural gas compressibility factor calculation formula, calculate the pressure value P of the formation after uplift time t. Pt The calculation formula.

[0058] Specifically, the pressure value P of the formation after uplift time t is calculated. Pt The calculation formula is as follows:

[0059]

[0060] Where A = -β w ·S w [1+α w (T t -T1)]-C pct

[0061]

[0062]

[0063] Among them, C pct P rt P pt T t and Z t These represent the formation compaction coefficient, overlying strata pressure, formation pressure, and temperature at time t during the formation uplift process, respectively; the natural gas compressibility factor; and the current formation state when the geological history time t is 0, which are a priori values; T1, P r1 P p1 S w1 Z1 and Z2 represent the formation temperature, overlying strata pressure, formation pressure, water saturation, and natural gas compressibility factor, respectively, before formation uplift (i.e., at maximum burial depth); α w β w P p0 、T0、ρ g ρ w and S gw The coefficients of thermal expansion of formation water, compressibility of formation water, pressure at the surface, temperature at the surface, density of natural gas under standard conditions, density of formation water, and solubility of natural gas in water are all a priori values; k is the residual coefficient of natural gas after dissipation; m and n are the coefficients in the formula for calculating the compressibility factor of natural gas.

[0064] Step 120, based on the pressure value P Pt The calculation formula uses the controlled variable method to quantitatively calculate the influence of multiple controlling factors during the tectonic uplift period on the current abnormally low pressure P. Pt The relative contribution of the formation is determined by various controlling factors, including uplift erosion, temperature reduction, natural gas loss, and dissolution-induced porosity.

[0065] Specifically, in order to quantitatively describe the contribution of each main controlling factor to the formation of abnormal low pressure, the control variable method is used to quantitatively calculate the contribution value: (1) To explore the effect of uplift and erosion on the reduction of formation pressure, it is possible to keep the formation temperature constant and prevent the loss of natural gas, i.e., T t =T1 and k=0 to calculate the corresponding contribution value ΔP Pa (2) To explore the effect of temperature reduction on formation pressure reduction, which can prevent formation rebound and natural gas loss, i.e., H t =H1 and k=0, to calculate the corresponding contribution value ΔP Pb (3) To explore the impact of other factors such as natural gas loss and dissolution-induced porosity on formation pressure reduction, the total formation pressure reduction can be subtracted from ΔP. Pa and ΔPPb Obtain the corresponding contribution value ΔP Pc .

[0066] The method provided by this invention calculates the pressure value P of the formation after uplift time t based on the formation compaction coefficient, overlying strata pressure, formation pressure, temperature, and natural gas compressibility factor at time t during formation uplift; the formation compaction coefficient, overlying strata pressure, formation pressure, temperature, and natural gas compressibility factor at geological history time t=0; the formation temperature, overlying strata pressure, formation pressure, water saturation, and natural gas compressibility factor before uplift; the formation hydrothermal expansion coefficient, formation water compressibility factor, surface pressure, surface temperature, natural gas density under standard conditions, formation water density, and natural gas solubility in water; and the residual coefficient of natural gas after dissipation, which are used as coefficients in the natural gas compressibility factor calculation formula. Pt The calculation formula is based on the pressure value P. Pt The calculation formula uses the controlled variable method to quantitatively calculate the influence of multiple controlling factors during the tectonic uplift period on the current abnormally low pressure P. Pt The relative contribution of the resulting formation is determined by various controlling factors, including uplift erosion, temperature reduction, natural gas loss, and dissolution-induced porosity. The method provided by this invention has wider applicability and greater practicality than previous methods, and possesses certain industrial application value.

[0067] Based on the above embodiments, step S110 in this method specifically includes:

[0068] Step S1: At any geological time t during the tectonic uplift process, the change in rock pore volume due to the decrease in overlying strata pressure is as follows:

[0069] V pt =V p1 (1-C pct ·Δσ efft ) Formula 1

[0070] In Formula 1, V p1 and V pt These represent the rock pore volumes before and after tectonic uplift, C pct and Δσ efft The changes in compaction coefficient and effective stress of the rock formation, respectively;

[0071] Step S2: Under relatively semi-closed strata conditions, due to the decrease in strata temperature and pressure caused by tectonic uplift, the volume of formation water and natural gas in the rock pores changes as follows:

[0072] V wt =V p1 ·S w1 [1+α w (Tt -T1)]·[1-β w (P pt -P p1 )] Formula 2

[0073]

[0074] In formulas 2 and 3, V wt V gt T t P pt m gt and Z t These represent the volume of formation water in the formation rock pores, the volume of natural gas, the formation temperature, the formation pressure, the mass of natural gas, and the natural gas compressibility factor at time t during the uplift process; V p1 S w1 T1 and P p1 These represent the pore volume, water saturation, formation temperature, and formation pressure before tectonic uplift, all of which are prior values; α w β w P p0 T0 and ρ g These are the thermal expansion coefficient of formation water, the compressibility coefficient of formation water, the pressure at the surface, the temperature at the surface, and the density of natural gas under standard conditions, all of which are a priori values.

[0075] Step S3: Under in-situ formation conditions, the natural gas stored in the pores undergoes dissolution by formation water and a certain degree of diffusion, resulting in a natural gas mass m. gt It becomes:

[0076]

[0077] In Formula 4, V p1 T1, P p1 Z1 and S w1 These represent the rock pore volume, formation temperature, formation pressure, natural gas compressibility factor, and water saturation before formation uplift; m g2 P p0 、T0、ρ g ρ w and S gw The following parameters were constructed: the mass of natural gas after uplift, the pressure at the surface, the temperature at the surface, the density of natural gas under standard conditions, the density of formation water, and the solubility of natural gas in water; k is the residual coefficient of natural gas after dissipation.

[0078] Step S4: For natural gas reservoirs, the rock pores are always filled with gas-water two-phase fluid during the formation uplift process. Therefore, the volume of formation pores is always equal to the volume of fluid, hence the following relationship exists:

[0079] Vpt =V wt +V gt Formula 5

[0080] In the formula, V pt V wt and V gt These represent the pore volume, formation water volume in the pores, and natural gas volume in the pores at time t after formation uplift, respectively.

[0081] Step S5: Change in effective stress Δσ efft It can be obtained according to the definition formula 6 of the formation effective stress:

[0082] Δσ efft =(P rt -P Pt )-(P r1 -P P1 ) Formula 6

[0083] In the formula, P Pt and P rt P represents the formation pressure at time t during the formation uplift process and the pressure of the overlying strata, respectively; these are prior values. P1 To determine the formation pressure prior to uplift, the pressure is obtained by measuring fluid inclusion trapping pressure or basin simulation methods; this is a priori value. r1 The pressure of the overlying strata before tectonic uplift is a priori value.

[0084] Step S6: Combine equations 1-6 to obtain the theoretical equations relating the rock formation compaction coefficient, the change in effective stress, and formation temperature and pressure:

[0085]

[0086] In the formula, P pt T t and Z t These represent the formation pressure, temperature, and natural gas compressibility factor at time t during the tectonic uplift process; when the geological history time t is 0, these are all prior values; C pct , Δσ efft These represent the changes in the compaction coefficient and effective stress of the rock formation at time t during tectonic uplift; V p1 T1, P p1 S w1 Z1 and Z2 represent the rock pore volume, formation temperature, formation pressure, water saturation, and natural gas compressibility factor before formation uplift, respectively; α w β w P p0 、T0、ρ g ρ w and S gwHere, represents the thermal expansion coefficient of formation water, the compressibility coefficient of formation water, the pressure at the surface, the temperature at the surface, the density of natural gas under standard conditions, the density of formation water, and the solubility of natural gas in water; k represents the residual coefficient of natural gas after dissipation.

[0087] Step S7: Solve the theoretical equation Formula 7, and based on the actual physical meaning of the relevant parameters, after eliminating invalid solutions to the equation, solve for the formation pressure value P at time t after uplift. Pt :

[0088] A·P Pt 2 +B·P Pt +C=0

[0089]

[0090] Where A = -β w ·S w [1+α w (T t -T1)]-C pct

[0091]

[0092]

[0093] Specifically, at any geological time t during the tectonic uplift process, the change in rock pore volume due to the decrease in pressure from the overlying strata is as follows:

[0094] V pt =V p1 (1-C pct ·Δσ efft )

[0095] In the formula, V p1 and V pt These represent the rock pore volumes before and after tectonic uplift, C pct and Δσ efft The changes in the compaction coefficient and effective stress of the rock formation, respectively.

[0096] Under relatively semi-closed strata conditions, the volume of formation water and natural gas in the rock pores changes due to the decrease in formation temperature and pressure caused by tectonic uplift:

[0097] V wt =V p1 ·S w1 [1+α w (T t -T1)]·[1-β w (P pt-P p1 )]

[0098]

[0099] In the formula, V wt V gt T t P pt m gt and Z t These represent the volume of formation water in the formation rock pores, the volume of natural gas, the formation temperature, the formation pressure, the mass of natural gas, and the natural gas compressibility factor at time t during the uplift process; V p1 S w1 T1 and P p1 The pore volume, water saturation, formation temperature, and formation pressure before uplift were constructed, representing prior values; α w β w P p0 T0 and ρ g These are the thermal expansion coefficient of formation water, the compressibility coefficient of formation water, the pressure at the surface, the temperature at the surface, and the density of natural gas under standard conditions, all of which are prior values.

[0100] Under in-situ formation conditions, the natural gas stored in the pores undergoes dissolution by formation water and a certain degree of diffusion, resulting in the following changes in mass:

[0101]

[0102] In the formula, V p1 T1, P p1 Z1 and S w1 These represent the rock pore volume, formation temperature, formation pressure, natural gas compressibility factor, and water saturation before formation uplift; m g2 P p0 、T0、ρ g ρ w and S gw The following parameters are constructed: the mass of natural gas after uplift, the pressure at the surface, the temperature at the surface, the density of natural gas under standard conditions, the density of formation water, and the solubility of natural gas in water; k is the residual coefficient of natural gas after dissipation.

[0103] For natural gas reservoirs, the rock pores are always filled with a gas-water two-phase fluid during the tectonic uplift process. Therefore, the volume of the formation pores is always equal to the volume of the fluid, i.e., the following relationship exists:

[0104] V pt =V wt +V gt

[0105] In the formula, V pt Vwt and V gt These represent the pore volume, formation water volume in the pores, and natural gas volume in the pores at time t after formation uplift, respectively.

[0106] Combining the above formulas, we obtain the theoretical equations relating the compaction coefficient of the rock formation, the change in effective stress, and formation temperature and pressure:

[0107]

[0108] In the formula, P pt T t and Z t These represent the formation pressure and temperature at time t during the tectonic uplift process, and the natural gas compressibility factor, respectively. When the geological history time t is 0, these are prior values; C pct and Δσ efft These represent the changes in the compaction coefficient and effective stress of the rock formation at time t during tectonic uplift; V p1 T1, P p1 S w1 Z1 and Z2 represent the rock pore volume, formation temperature, formation pressure, water saturation, and natural gas compressibility factor before formation uplift, respectively; α w β w P p0 、T0、ρ g ρ w and S gw denoted by , where is the thermal expansion coefficient of formation water, the compressibility coefficient of formation water, the pressure at the surface, the temperature at the surface, the density of natural gas under standard conditions, the density of formation water, and the solubility of natural gas in water; and k is the residual coefficient of natural gas after dissipation.

[0109] Change in effective stress Δσ efft The effective stress of the formation can be obtained using the following formula.

[0110] Δσ efft =(P rt -P Pt )-(P r1 -P P1 )

[0111] In the formula, P Pt and P rt P represents the formation pressure at time t during the formation uplift process and the pressure of the overlying strata, respectively; these are prior values. P1 To determine the formation pressure prior to uplift (at maximum burial depth), this can be obtained by measuring fluid inclusion trapping pressure or basin simulation methods; these are prior values. r1 The pressure of the overlying strata before structural uplift (at the maximum burial depth) is a priori value.

[0112] The relationship between the pressure in a clastic reservoir after tectonic uplift and the main controlling factors of low-pressure formation can be obtained by simultaneously solving the above formulas to obtain a theoretical equation. Based on the actual physical meaning of the relevant parameters, after eliminating invalid solutions to the equation, the pressure value of the corresponding formation at time t after uplift can be solved, as shown in the following formula:

[0113] A·P Pt 2 +B·P Pt +C=0

[0114]

[0115] For ease of expression, P Pt In the calculation formula, A, B, and C are represented by the following formulas respectively:

[0116] A = -β w ·S w [1+α w (T t -T1)]-C pct

[0117]

[0118]

[0119] In the formula, C pct P rt P pt T t and Z t These represent the formation compaction coefficient, overlying strata pressure, formation pressure, temperature, and natural gas compressibility factor at time t during the formation uplift process. When the geological history time t is 0, the current formation state is represented, and these are a priori values; T1, P r1 P p1 S w1 Z1 and Z2 represent the formation temperature, overlying strata pressure, formation pressure, water saturation, and natural gas compressibility factor, respectively, before formation uplift (i.e., at maximum burial depth); α w β w P p0 、T0、ρ g ρ w and S gw The coefficients of thermal expansion of formation water, compressibility of formation water, pressure at the surface, temperature at the surface, density of natural gas under standard conditions, density of formation water, and solubility of natural gas in water are all a priori values; k is the residual coefficient of natural gas after dissipation; m and n are the coefficients in the formula for calculating the compressibility factor of natural gas.

[0120] Based on the above embodiments, the method further includes the following step before step S1:

[0121] Test rocks under different effective stresses σ eff Pore ​​volume and rock compaction coefficient of the lower sandstone, fitting the rock pore volume and effective stress σ eff ;

[0122] Based on the rock pore volume and effective stress σ of different rock samples eff The power-law fitting formula is used to obtain the relationship between rock porosity φ and formation compaction coefficient C. pc The fitting relationship.

[0123] Specifically, Table 1 presents the core sample information of clastic rocks from a certain stratum in a certain area of ​​a cratonic sedimentary basin. As shown in Table 1 below, a series of tight sandstone samples from clastic strata in a certain area of ​​a cratonic sedimentary basin were selected, and the rocks were tested under different confining pressures (effective stress σ). eff The discrete values ​​of pore volume in the lower sandstone. Figure 2 This is a schematic diagram illustrating the change in pore volume of clastic rock samples as effective stress increases, provided by the present invention. Figure 2 As shown, the discrete values ​​of pore volume of sandstone under different confining pressures are tested.

[0124] Table 1. Information on core samples of clastic rocks from a specific stratiform section within a cratonic sedimentary basin.

[0125]

[0126] Figure 3 This is a schematic diagram illustrating the change in the compaction coefficient of clastic rock samples as effective stress increases, provided by the present invention. The diagram shows the changes in the compaction coefficient of the formation with increasing effective stress σ. eff Discrete values ​​of rock pore volume from lower clastic rock samples were used to calculate the corresponding rock formation compaction coefficient (e.g., Figure 3 As shown in the figure, it can be seen that the rock pore volume and effective stress have a good correlation, and a nonlinear power equation is used to fit the two (e.g. Figure 1 (as shown);

[0127] Figure 4 This is a schematic diagram illustrating the change in rock pore volume with increasing effective stress under an effective stress of 55 MPa, provided by the present invention. The diagram is based on the rock pore volume and effective stress σ of different rock samples. eff The power-law fitting formula expands the effective stress range from σ eff The effective stress σ, which is the effective stress of in-situ formation conditions, is extended from laboratory conditions of 0–40 MPa to in-situ formation conditions. eff ≈55MPa, the rock porosity φ and formation compaction coefficient C of the strata in this region were obtained. pc Under effective stress σ eff A series of discrete values ​​≈55MPa (e.g.) Figure 4As shown in the figure, the correlation between the two was obtained, expressed by the following formula, with a correlation coefficient of 0.9184, indicating a good fit.

[0128] C pc =1×10 -8 e -0.248φ

[0129] In the formula, C pc φ is the rock formation compaction coefficient, Pa⁻¹; φ is the rock porosity, %.

[0130] Based on the above embodiments, in this method, the rock porosity φ and the formation compaction coefficient C are used as the basis. pc The fitting relationship is used to obtain the compaction coefficient and porosity of the rock formation and convert them into values ​​at time t during the uplift process.

[0131] Specifically, the following formula obtained through fitting is used.

[0132] C pc =1×10 -8 e -0.248φ

[0133] Converting the rock formation compaction coefficient and porosity in the above formula into values ​​at time t during the uplift process, we can obtain C. pct The expression:

[0134]

[0135] In the formula, φ t The porosity at time t during the lifting process is used to determine the porosity.

[0136] Based on the above embodiments, in this method, the test rock is subjected to different effective stresses σ eff The method for determining the pore volume and compaction coefficient of the underlying sandstone formation is to use a PoroPDP-200 overburden pressure permeability meter to test the compaction coefficient and pore volume of the formation using the helium method.

[0137] Specifically, the method for obtaining the compaction coefficient and pore volume of rock formations is as follows: the compaction coefficient and pore volume of rock formations are tested using the helium method with a PoroPDP-200 overburden pressure permeability measuring instrument.

[0138] Based on the above embodiments, in this method, the compressibility factor Z of natural gas is calculated by fitting a Standing chart to the relationship between temperature and pressure.

[0139] Specifically, in clastic reservoirs, the compressibility factor Z of natural gas is calculated by fitting the Standing (1952) plate to the relationship between temperature and pressure, and is expressed by the following formula:

[0140] Z = 0.2173 m·PPt +n

[0141] in:

[0142] m = 0.0218(T) t / T c ) 2 -0.1245T t / T c +0.2091

[0143] n = 0.2315(T) t / T c ) 2 +1.333T t / T c -1.0634

[0144] In the formula, P Pt T t These represent the formation pressure and temperature at time t during the formation uplift process; T c Let be the critical temperature of natural gas, and be a priori value.

[0145] Based on the above embodiments, in this method, the formation water thermal expansion coefficient α w Formation water compressibility coefficient β w Surface pressure P p0 Surface temperature T0, density of natural gas under standard conditions ρ g Density ρ of formation water w The solubility of natural gas in water (S) gw Critical temperature T of natural gas c All values ​​are based on laboratory test experience.

[0146] Specifically, the formation hydrothermal expansion coefficient α w Formation water compressibility coefficient β w Surface pressure P p0 Surface temperature T0, density of natural gas under standard conditions ρ g Density ρ of formation water w The solubility of natural gas in water (S) gw Critical temperature T of natural gas c The empirical values ​​for relevant parameters in the quantitative evaluation model for the causes of abnormal low pressure were determined using laboratory testing. Table 2 shows the empirical values ​​for these parameters as follows:

[0147] Table 2. Empirical values ​​of relevant parameters in the quantitative evaluation model for the causes of abnormal low pressure.

[0148]

[0149] Based on the above embodiments, in this method, the porosity φ at time t during the lifting process...t An approximate calculation was performed using the current depth-sonic transit time-measured porosity relationship exponential model, which correlates time t with formation depth H during the uplift process. t The functional relationship was obtained from the basin's simulated burial history map, and the overlying strata pressure P at time t during the tectonic uplift process was... rt Calculated according to a preset formula.

[0150] Specifically, the porosity φ at time t during the lifting process. t An approximate calculation can be made using the current depth-sonic transit time-measured porosity relationship exponential model:

[0151]

[0152] In the formula, φ0 is the current porosity, an a priori value; e is the base of the natural logarithm, an a priori value; k is the normal compaction factor of the formation, an a priori value; H t H is the stratum depth at time t during the uplift process; H0 is the current stratum depth, a priori value.

[0153] Figure 5 This invention provides a depth-geological-time evolution diagram of clastic rocks at a depth of 3500m in a single well within a cratonic sedimentary basin, showing the relationship between time t and formation depth H during the uplift process. t The functional relationship can be based on the basin simulation burial history map ( Figure 5 For example, sample A-12 is currently buried at a depth of 3500m. At t=100Ma, the burial depth H1 before structural uplift was 4028.9m.

[0154] H t =f(t)

[0155] The overlying formation pressure P at time t during the tectonic uplift process rt It can be calculated using the following formula:

[0156] P rt =ρ s ·H t ·g

[0157] In the formula, ρ s The density of shallow strata is an empirical value, a priori, and is taken as 2.65 g / cm³. 3 H t Let t be the formation depth at time t during the tectonic uplift process; g is the gravitational acceleration, taken as 9.8 m / s². 2 For example, if sample A-12 is currently buried at a depth of 3500m, and at t=100Ma, the overlying stratum pressure P was 4028.9m before tectonic uplift. r1 =104.6MPa.

[0158] Based on the above embodiments, in this method, the formation temperature T at time t during the uplift process is... t The formation temperature T1 before uplift was obtained based on the temperature-geological time evolution diagram of the basin thermal history simulation.

[0159] Specifically, Figure 6 This invention provides a temperature-geological-time evolution diagram of clastic rocks at a depth of 3500m in a single well within a cratonic sedimentary basin, showing the formation temperature T at time t during the uplift process. t The formation temperature T1 before uplift can be obtained from the basin thermal history simulation temperature-geological time evolution diagram. Figure 6 )get.

[0160] Based on the above embodiments, the method further includes: quantitatively calculating the contribution value of each main control factor to low pressure through step S120, which requires obtaining the key parameter values ​​of reservoir rock porosity, formation temperature and pressure before and after formation tectonic uplift.

[0161] Specifically, Table 3 shows the key parameters of a single well in a cratonic sedimentary basin before and after the uplift of clastic rock formations. Step S120 quantitatively calculates the contribution of each controlling factor to low pressure, requiring the acquisition of key parameters such as reservoir porosity, formation temperature, and pressure before and after the tectonic uplift, as shown in Table 3 below:

[0162] Table 3 Key parameters of clastic strata before and after uplift in a single well in a cratonic sedimentary basin.

[0163]

[0164] Figure 7 This is a schematic diagram illustrating the relative contribution of the main controlling factors in evaluating the formation of abnormal low pressure in a single well, provided by the present invention. Using the method of this embodiment, the relative contribution of each main controlling factor during the formation tectonic uplift period to the current abnormal low pressure is calculated. Figure 7 (the bar chart section) and percentage ( Figure 7 (The broken line graph part in the figure) This method can more accurately estimate the contribution of pore rebound, geothermal decrease, natural gas loss and other factors to pressure reduction. It has stronger applicability and practicality than previous methods, and can continuously calculate paleopressure values ​​for various historical periods, which has certain guiding significance for oil and gas exploration evaluation.

[0165] This invention addresses the challenge of quantitatively evaluating the main controlling factors in the formation of abnormal low pressure in clastic natural gas reservoirs. It proposes a quantitative evaluation model for the genesis of abnormal low pressure built within a gas-water two-phase fluid computational system. This model, to some extent, solves the problems of limited application scope and lack of coupling between various factors in previous quantitative calculations of abnormal low pressure genesis. This method achieves better results in quantitatively evaluating the contribution of each main controlling factor to the formation of current abnormal low pressure, and has wider applicability and greater practicality than previous methods, possessing certain industrial application value.

[0166] This invention analyzes test data on the overburden pore volume and formation compaction coefficient of tight sandstone samples in the study area, and fits a formula for the relationship between formation compaction coefficient and porosity (depth) under in-situ effective stress conditions. Taking into full account the coexistence of gas-water two-phase fluids under formation conditions, a coupled equation is established for the changes in pore and fluid volume before and after tectonic uplift and various controlling factors. Starting with the paleotemperature and paleopressure of the formation at the maximum burial depth, and combining simulated formation temperature and actual calculated porosity evolution curves, the controlled variable method is used to quantitatively evaluate the relative contributions of various controlling factors during tectonic uplift to the formation of the current anomalous low pressure.

[0167] Addressing the challenge of quantitatively evaluating the controlling factors of abnormal low pressure formation in clastic natural gas reservoirs, this paper proposes a new method for quantitatively evaluating the genesis of abnormal low pressure. This method uses the rock formation compaction coefficient, formation fluid compressibility coefficient, and thermal expansion coefficient as key parameters in a theoretical model, and the actual equation of state for natural gas as its theoretical foundation. It establishes a quantitative relationship between the changes in pore volume and multiphase fluid volume per unit geological body before and after formation uplift. Furthermore, it constructs a theoretical coupling model of formation pressure and multiple key parameters to solve the quantitative relationship between present-day abnormal formation pressure and the controlling factors. This novel method for quantitatively evaluating the genesis of abnormal low pressure is characterized by readily obtainable key parameters, low testing costs for overburden pore volume and rock formation compaction coefficient, and good applicability to natural gas reservoirs. It addresses, to some extent, the problems of previous methods lacking experimental data support, lacking correlation and coupling between quantitative calculations of multiple controlling factors, and producing mostly qualitative to semi-quantitative evaluation results. It has wide applicability and plays an important role in basin analysis and hydrocarbon accumulation dynamics research, possessing significant industrial application value in oil and gas exploration and evaluation.

[0168] The device embodiments described above are merely illustrative. The units described as separate components may or may not be physically separate. The components shown as units may or may not be physical units; that is, they may be located in one place or distributed across multiple network units. Some or all of the modules can be selected to achieve the purpose of this embodiment according to actual needs. Those skilled in the art can understand and implement this without any creative effort.

[0169] Through the above description of the embodiments, those skilled in the art can clearly understand that each embodiment can be implemented by means of software plus necessary general-purpose hardware platforms, and of course, it can also be implemented by hardware. Based on this understanding, the above technical solutions, in essence or the part that contributes to the prior art, can be embodied in the form of a software product. This computer software product can be stored in a computer-readable storage medium, such as ROM / RAM, magnetic disk, optical disk, etc., and includes several instructions to cause a computer device (which may be a personal computer, server, or network device, etc.) to execute the methods described in the various embodiments or some parts of the embodiments.

[0170] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention, and not to limit them; although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some of the technical features; and these modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the embodiments of the present invention.

Claims

1. A quantitative calculation method for the genesis of abnormally low pressure in clastic gas reservoirs, characterized in that, include: Step S110: Based on time during formation uplift Formation compaction coefficient, overlying strata pressure, formation pressure, temperature, and natural gas compressibility factor at that time, geological history. The formula includes: formation compaction coefficient (when t = 0), overlying strata pressure, formation pressure, temperature, and natural gas compressibility factor; formation temperature, overlying strata pressure, formation pressure, water saturation, and natural gas compressibility factor before uplift; formation hydrothermal expansion coefficient, formation water compressibility factor, surface pressure, surface temperature, natural gas density under standard conditions, formation water density, and natural gas solubility in water; residual coefficient of natural gas after dissipation; coefficients for calculating the natural gas compressibility factor; and the pressure value of the formation after uplift time t. The calculation formula; Step S120: Based on the pressure value The calculation formula uses the controlled variable method to quantitatively calculate the influence of multiple controlling factors during the tectonic uplift period on the current abnormal low pressure. The relative contribution of the formation, wherein the various controlling factors include uplift erosion, temperature reduction, natural gas loss and dissolution porosimetry; Specifically, step S110 includes: Step S1: At any geological time t during the tectonic uplift process, the change in rock pore volume due to the decrease in overlying strata pressure is as follows: Formula 1 In formula 1, and These represent the rock pore volume before and after tectonic uplift. and The changes in the compaction coefficient and effective stress of the rock formation, respectively; Step S2: Under relatively semi-closed strata conditions, due to the decrease in strata temperature and pressure caused by tectonic uplift, the volume of formation water and natural gas in the rock pores changes as follows: Formula 2 Formula 3 In formulas 2 and 3, , , , , and The time during the lifting process are respectively The volume of formation water in the pores of the formation rocks, the volume of natural gas, the formation temperature, the formation pressure, the mass of natural gas, and the compressibility factor of natural gas; , , and These are the pore volume, water saturation, formation temperature, and formation pressure before tectonic uplift, all of which are a priori values. , , , and These are the thermal expansion coefficient of formation water, the compressibility coefficient of formation water, the pressure at the surface, the temperature at the surface, and the density of natural gas under standard conditions, all of which are a priori values. Step S3: Under in-situ formation conditions, the natural gas stored in the pores undergoes dissolution by formation water and a certain degree of diffusion, resulting in a decrease in the quality of the natural gas. It becomes: Formula 4 In formula 4, , , , and These are the rock pore volume, formation temperature, formation pressure, natural gas compressibility factor, and water saturation before formation uplift; , , , , and The following parameters were determined: the mass of natural gas after uplift, the pressure at the surface, the temperature at the surface, the density of natural gas under standard conditions, the density of formation water, and the solubility of natural gas in water. This represents the residual coefficient of natural gas after it has dissipated. Step S4: For natural gas reservoirs, the rock pores are always filled with gas-water two-phase fluid during the formation uplift process. Therefore, the volume of formation pores is always equal to the volume of fluid, hence the following relationship exists: Formula 5 In the formula, , and The time after the strata uplift Hourly pore volume, pore water volume in pores, and pore natural gas volume; Step S5: Change in effective stress The effective stress of the formation is obtained according to Formula 6, which defines the effective stress of the formation. Formula 6 In the formula, and During the strata uplift process The pressure of the formation and the pressure of the overlying strata are a priori values. To construct the formation pressure before uplift, the pressure is obtained by measuring fluid inclusion trapping pressure or basin simulation methods, and is a priori value. The pressure of the overlying strata before tectonic uplift is a priori value. Step S6: Combine equations 1-6 to obtain the theoretical equations relating the rock formation compaction coefficient, the change in effective stress, and formation temperature and pressure: Formula 7 In the formula, , and The time during the tectonic uplift process are respectively Formation pressure, temperature, and natural gas compressibility factor at that time, in the local geological history When the value is 0, all values ​​are prior values; , The time during the tectonic uplift process are respectively The changes in the compaction coefficient and effective stress of the rock formation over time; , , , and These are the rock pore volume, formation temperature, formation pressure, water saturation, and natural gas compressibility factor before formation uplift. , , , , , and The parameters are: thermal expansion coefficient of formation water, compressibility coefficient of formation water, pressure at the surface, temperature at the surface, density of natural gas under standard conditions, density of formation water, and solubility of natural gas in water. This represents the residual coefficient of natural gas after it has dissipated. Step S7: Solve the theoretical equation Formula 7, and based on the actual physical meaning of the relevant parameters, after eliminating invalid solutions to the equation, solve for the corresponding formation time after uplift. Formation pressure value As shown in Formula 8: Formula 8 in, 。 2. The quantitative calculation method for the abnormal low-pressure origin of clastic gas reservoirs according to claim 1, characterized in that, Before step S1, the following is also included: Test rocks under different effective stresses Pore ​​volume and rock formation compaction coefficient of lower sandstone, fitting rock pore volume and effective stress ; Based on the rock pore volume and effective stress of different rock samples The power-law fitting relationship is used to obtain the rock porosity. With formation compaction coefficient The fitting relationship.

3. The quantitative calculation method for the abnormal low-pressure origin of clastic gas reservoirs according to claim 2, characterized in that, Based on rock porosity With formation compaction coefficient The fitting relationship is used to obtain the compaction coefficient and porosity of the rock formation and convert them into the uplift process. The value at time.

4. The quantitative calculation method for the abnormal low-pressure origin of clastic gas reservoirs according to claim 2, characterized in that, Test rocks under different effective stresses The method for determining the pore volume and compaction coefficient of the underlying sandstone formation is to use a PoroPDP-200 overburden pressure permeability meter to test the compaction coefficient and pore volume of the formation using the helium method.

5. The quantitative calculation method for the abnormal low-pressure origin of clastic gas reservoirs according to claim 1, characterized in that, natural gas compressibility The calculations were obtained by fitting a Standing chart to the relationship between temperature and pressure.

6. The quantitative calculation method for the abnormal low-pressure origin of clastic gas reservoirs according to claim 1, characterized in that, Formation hydrothermal expansion coefficient Formation water compressibility coefficient Surface pressure Surface temperature Density of natural gas under standard conditions Density of formation water Solubility of natural gas in water Critical temperature of natural gas All values ​​are based on laboratory test experience.

7. The quantitative calculation method for the abnormal low-pressure origin of clastic gas reservoirs according to claim 1, characterized in that, time during the lifting process porosity at time Using the current depth-sonic transit time-measured porosity relationship index model for approximate calculation, the time during the uplift process... With stratum depth The functional relationship was obtained from the basin simulation burial history map, and the time during the tectonic uplift process... Overlying strata pressure at time Calculated according to a preset formula.

8. The quantitative calculation method for the abnormal low-pressure origin of clastic gas reservoirs according to claim 1, characterized in that, time during the lifting process Formation temperature at time and the temperature of the formation before uplift Obtained based on the temperature-geological time evolution map simulated from the basin's thermal history.

9. The quantitative calculation method for the abnormal low-pressure origin of clastic gas reservoirs according to claim 1, characterized in that, Also includes: Step S120 involves quantitatively calculating the contribution of each controlling factor to low pressure, requiring the acquisition of key parameter values ​​for reservoir rock porosity, formation temperature, and pressure before and after tectonic uplift.

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