A method and system for determining adjacent lithology paleo-barrier oil column height

Abstract

This invention provides a method and system for determining the height of paleopustrated oil columns in adjacent lithologies. The height determination method includes: Step S1: Identifying lithology types based on core observation and thin-section image analysis; Step S2: Conducting porosity, permeability, and oil-water displacement pressure tests to establish a quantitative functional relationship between porosity, permeability, and oil-water breakthrough radius; Step S3: Conducting petrographic observation of thin sections and fluid inclusions, homogenization temperature testing, and burial history analysis to establish a diagenetic-reservoir evolution sequence; Step S4: Performing porosity evolution reconstruction to obtain paleoporosity and paleopermeability during the reservoir formation period; Step S5: Performing permeability evolution reconstruction to obtain paleodisplacement pressure; Step S6: Calculating the paleooil column height based on the difference in paleodisplacement pressure. This provides an effective method for studying the paleopustrated capacity of lithological traps during oil reservoir formation.

Description

Technical Field

[0001] This invention relates to the field of oil and gas exploration, and in particular to a method and system for determining the height of adjacent lithological paleo-blocking oil columns. Background Technology

[0002] Lithological traps are traps formed by changes in lithology or physical properties. These changes can occur during sedimentary processes, as well as during diagenesis and epigenetic processes. The height of the oil column in a lithological trap is controlled by the displacement pressure difference between adjacent lithologies with different physical properties. The oil column height reaches its maximum value when the upward buoyancy of the oil equals the displacement pressure difference between adjacent lithologies. The lithological combination with the minimum oil column height ultimately determines the oil column height of the lithological trap.

[0003] The displacement pressure difference between adjacent lithologies within a lithological trap is jointly controlled by their absolute physical properties and their grade differences. The current displacement pressure difference between adjacent lithologies within a lithological trap can be calculated using current physical property data, and thus the maximum oil column height that can be sealed between adjacent lithologies can be calculated. However, most lithological traps have undergone multiple phases of oil charging and accumulation, and the paleophysical properties of adjacent lithologies within the trap during the paleoclimate accumulation period cannot be directly obtained. This makes it impossible to calculate the paleodisplacement pressure difference and the paleosealing oil column height between adjacent lithologies within a lithological trap. The paleosealing oil column height between adjacent lithologies within a lithological trap has a significant impact on the effectiveness of the lithological trap, thereby affecting the distribution patterns and exploration and development deployment of lithological reservoirs. For example, in the early stages of oil charging and reservoir formation, if the ancient plugging oil column height of the lithological trap is low, an ancient lithological reservoir cannot be formed. The lithological diagenesis in the lithological trap that has not been charged with oil continues, eventually evolving into an ineffective reservoir. In the late stages of oil charging, even if the plugging oil column height of the lithological trap is very high, it is still difficult to form a lithological reservoir due to the lack of an effective reservoir. Summary of the Invention

[0004] In view of the above problems, the present invention is proposed to provide a method and system for determining the height of adjacent lithological paleo-plugging oil columns in order to overcome or at least partially solve the above problems.

[0005] According to one aspect of the present invention, a method for determining the height of adjacent lithological paleopustration oil columns is provided, the height determination method comprising:

[0006] Step S1: Identify the lithology type based on core observation and thin section image analysis of the cast body;

[0007] Step S2: Conduct porosity, permeability, and oil-driven water displacement pressure tests to establish a quantitative functional relationship between porosity, permeability, and oil-driven water breakthrough radius;

[0008] Step S3: Conduct petrographic observations of cast thin sections and fluid inclusions, perform homogenization temperature tests, and analyze burial history to establish a diagenetic-accumulation evolution sequence;

[0009] Step S4: Perform porosity evolution reconstruction to obtain paleoporosity and paleopermeability during the hydrocarbon accumulation period;

[0010] Step S5: Perform permeability evolution recovery to obtain ancient displacement pressure;

[0011] Step S6: Calculate the height of the ancient oil-bearing column based on the difference in ancient displacement pressure.

[0012] Optionally, step S1: Identifying the lithology type based on core observation and thin section image analysis specifically includes:

[0013] The rock core was used to identify the locations where various lithologies changed abruptly, and rock core samples were taken from two adjacent lithology types.

[0014] The long axis is measured to determine the lithology type according to the grain size classification standard for clastic rocks.

[0015] Optionally, step S2: conducting porosity, permeability, and oil-driven water displacement pressure tests, and establishing a quantitative functional relationship between porosity, permeability, and oil-driven water breakthrough radius specifically includes:

[0016] For each lithological type, samples were taken for porosity, permeability, and oil-driven water displacement pressure tests to obtain porosity, permeability, and oil-driven water displacement pressure data, and to establish a quantitative functional relationship between porosity, permeability, and oil-driven water breakthrough radius.

[0017] Optionally, step S3: performing petrographic observation of cast thin sections and fluid inclusions, homogenization temperature testing, and burial history analysis to establish a diagenetic-accumulation evolution sequence specifically includes:

[0018] By comprehensively utilizing methods such as thin section observation of cast bodies, petrographic observation of fluid inclusions, homogenization temperature testing, and burial history analysis, the chronological sequence of diagenesis and the periods and corresponding times of oil charging were analyzed to establish a diagenesis-reservoir evolution sequence.

[0019] Optionally, step S4: porosity evolution restoration specifically includes: restoring paleophysiological evolution through diagenesis-reservoir formation evolution sequence to obtain paleoporosity and paleopermeability during reservoir formation.

[0020] Optionally, step S5: performing permeability evolution recovery to obtain ancient displacement pressure specifically includes:

[0021] By utilizing the quantitative functional relationship between porosity, permeability, and the oil-driven water breakthrough radius, the paleodisplacement pressure during the hydrocarbon accumulation period of each lithology was determined.

[0022] Optionally, step S6: calculating the ancient oil-bearing column height based on the difference in ancient displacement pressures specifically includes:

[0023] By using the evolution curves of porosity and permeability, the ancient porosity and ancient permeability of the oil-filling and reservoir-forming period and its corresponding ancient burial depth were obtained.

[0024] Using paleoporosity and paleopermeability data, (K / Ф) 1 / 2 The linear relationship between the oil-water flooding breakthrough radius Rt and the reservoir formation radius Rt is used to obtain the oil-water flooding breakthrough radius Rt during the reservoir formation period.

[0025] Calculate the ancient oil displacement pressure during the reservoir formation period;

[0026] The height of the ancient plugging oil column in adjacent lithology during the hydrocarbon accumulation period was obtained using Formula 36.

[0027] Z omax =ΔP / (ρ w -ρ o (Formula 36)

[0028] Maximum oil column height: Z omax m; water density: ρ w =1Kg / m 3 Oil density: ρ o =0.9Kg / m 3 Gravitational constant: g = 9.8 m / s² 2 Displacement pressure difference between adjacent lithologies: ΔP, MPa.

[0029] Optionally, step S2: conducting porosity, permeability, and oil-driven water displacement pressure tests, and establishing a quantitative functional relationship between porosity, permeability, and oil-driven water breakthrough radius specifically includes:

[0030] Using a gas porosimeter and a gas permeability meter, the porosity and permeability of selected samples were obtained at room temperature and pressure according to the core analysis method.

[0031] Using a diagenetic simulation high-temperature and high-pressure displacement system, experimental water was prepared according to the formation water properties of the sample's stratum. The experimental water prepared by drying, vacuuming, and high-pressure saturation of the selected sample was placed into the high-temperature and high-pressure displacement system. The formation temperature and formation pressure of the sample's stratum were set, crude oil was injected, and oil-water displacement experiments were carried out.

[0032] Record the penetration pressure and penetration time twice to obtain the two rock sample penetration pressures P1 and P2 and the corresponding penetration times t1 and t2. Substitute the rock sample penetration pressure and penetration time obtained from the two tests into the Poisson equation (Formula 1) to obtain the oil-displacement pressure value P0 of the rock sample. Calculate the oil-displacement water breakthrough radius Rt using Formulas 2 and 3.

[0033] P0=(P2t2-P1t1) / (t2-t1) (Formula 1)

[0034] Rt=2 cosθ / P0 (Formula 2)

[0035] σ=40.5*T0 -0.149 (Formula 3)

[0036] P0 is the oil-driven water displacement pressure, MPa; P1 is the penetration pressure 1, MPa; P2 is the penetration pressure 2, MPa; t1 is the penetration time 1, min; t2 is the penetration time 2, min; Rt is the oil-driven water breakthrough radius, μm; is the oil-water interfacial tension, mN / m; θ is the petroleum wetting contact angle, °; T0 is the experimental temperature, ℃.

[0037] Multiple sets of the above experimental procedures were performed to obtain data on porosity Ф, permeability K, and the corresponding oil-driven water displacement pressure P0, and the (K / Ф) ratio was calculated. 1 / 2 The oil-driven water displacement breakthrough radius Rt is expressed in Excel as (K / Ф). 1 / 2 Let Rt be the x-axis and (K / Ф) be the oil-driven water breakthrough radius Rt. Establish a relationship between Rt and (K / Ф). 1 / 2 Quantitative functional relationship.

[0038] Optionally, step S3: performing petrographic observation of cast thin sections and fluid inclusions, homogenization temperature testing, and burial history analysis to establish a diagenetic-accumulation evolution sequence specifically includes:

[0039] Using a polarizing microscope and camera system, we observed the diagenetic phenomena of authigenic mineral replacement and dissolution-filling relationships in thin sections of cast bodies to determine the chronological order of each diagenetic process.

[0040] Using optical microscopy, we conducted petrographic observations and descriptions of fluid inclusions;

[0041] Two-phase brine inclusions of gas and liquid in cement were selected, along with two-phase brine inclusions of gas and liquid with different fluorescent colors of hydrocarbon inclusions. According to industry standards, the two-phase brine inclusions were heated using a hot and cold stage to transform the two phases into a single phase, restoring the single-phase state at the time of the formation of the two-phase brine inclusions. The instantaneous temperature was the homogenization temperature of the two-phase brine inclusions.

[0042] The homogenization temperature of gas-liquid two-phase brine inclusions in cement represents the formation temperature during cement precipitation. By projecting the homogenization temperature of gas-liquid two-phase brine inclusions in cement onto the burial history map, the formation time of cementation and the paleoburial depth of each well can be determined.

[0043] Homogenization temperatures of gas-liquid two-phase brine inclusions contemporaneous with hydrocarbon inclusions of different fluorescent colors represent formation temperatures during oil charging. By projecting homogenization temperatures onto the burial history map, the oil charging period and its corresponding paleoburial depth can be determined. Combined with the formation time of cementation and the paleoburial depth in each well, a diagenetic-reservoir evolution sequence can be established.

[0044] Optionally, the petrographic observation and description of fluid inclusions includes the identification of fluid inclusion shape, size, gas-liquid ratio, brine inclusions and hydrocarbon inclusions, fluorescence color of hydrocarbon inclusions, host minerals, and paragenetic assemblage relationships.

[0045] This invention also provides a system for determining the height of adjacent lithological paleo-suppressed oil columns, applying the aforementioned method for determining the height of adjacent lithological paleo-suppressed oil columns. The height determination system includes:

[0046] The lithology type identification module is used to identify lithology types based on core observation and thin section image analysis of cast bodies;

[0047] The quantitative functional relationship establishment module is used to conduct porosity, permeability and oil-driven water displacement pressure tests, and to establish a quantitative functional relationship between porosity, permeability and oil-driven water breakthrough radius;

[0048] The evolutionary sequence establishment module is used for petrographic observation of cast thin sections and fluid inclusions, homogenization temperature testing, and burial history analysis to establish a diagenetic-accumulation evolutionary sequence.

[0049] The porosity evolution recovery module is used to recover porosity evolution and obtain paleoporosity and paleopermeability during the hydrocarbon accumulation period.

[0050] The permeability evolution recovery module is used to recover permeability evolution and obtain ancient displacement pressures;

[0051] The ancient oil-bearing column height calculation module is used to calculate the ancient oil-bearing column height based on the difference in ancient displacement pressure.

[0052] This invention provides a method and system for determining the height of ancient oil columns in adjacent lithologies. The height determination method includes: Step S1: Identifying lithology types based on core observation and thin-section image analysis; Step S2: Conducting porosity, permeability, and oil-water displacement pressure tests to establish a quantitative functional relationship between porosity, permeability, and oil-water breakthrough radius; Step S3: Conducting petrographic observation of thin sections and fluid inclusions, homogenization temperature testing, and burial history analysis to establish a diagenetic-reservoir evolution sequence; Step S4: Performing porosity evolution reconstruction to obtain paleoporosity and paleopermeability during the reservoir formation period; Step S5: Performing permeability evolution reconstruction to obtain paleodisplacement pressure; Step S6: Calculating the height of the ancient oil column based on the difference in the paleodisplacement pressure. This method solves the problem of quantitatively calculating the height of ancient oil columns in adjacent lithologies within lithological traps during geological history, and provides an effective method for studying the paleo-plugging capacity of lithological traps during oil reservoir formation.

[0053] The above description is merely an overview of the technical solution of the present invention. In order to better understand the technical means of the present invention and to implement it in accordance with the contents of the specification, and to make the above and other objects, features and advantages of the present invention more apparent and understandable, specific embodiments of the present invention are described below. Attached Figure Description

[0054] To more clearly illustrate the technical solutions of the embodiments of the present invention, the drawings used in the following description of the embodiments will be briefly introduced. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0055] Figure 1 A flowchart illustrating a method for determining the height of adjacent lithological paleopustration oil columns provided in an embodiment of the present invention;

[0056] Figure 2 This is a schematic diagram of the porosity evolution and recovery process provided in an embodiment of the present invention;

[0057] Figure 3 A graph showing the relationship between (K / φ)¹ / ² and the oil-water displacement breakthrough radius (Rt) provided for embodiments of the present invention;

[0058] Figure 4 A geological history evolution diagram of a coarse sandstone sample buried at a depth of 3738.7m provided for embodiments of the present invention;

[0059] Figure 5 Fitting diagrams of the K and K / Ф function relationships for different planar pore structure types provided in embodiments of the present invention;

[0060] Figure 6This is a diagram showing the evolution of physical properties of gravelly sandstone during geological history, provided for an embodiment of the present invention. Detailed Implementation

[0061] Exemplary embodiments of the present disclosure will now be described in more detail with reference to the accompanying drawings. While exemplary embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure may be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art.

[0062] The terms "comprising" and "having," and any variations thereof, in the specification, embodiments, claims, and drawings of this invention are intended to cover non-exclusive inclusion, such as including a series of steps or units.

[0063] The technical solution of the present invention will be further described in detail below with reference to the accompanying drawings and embodiments.

[0064] Example 1

[0065] like Figure 1 As shown, this invention aims to accurately calculate the height of the paleo-blocking oil column in adjacent lithological traps. First, lithological types are determined using core samples from the cored well section and thin sections of cast bodies. At least three samples of each lithological type are taken for porosity, permeability, and oil-water displacement pressure tests to obtain porosity, permeability, and oil-water displacement pressure data, establishing a quantitative functional relationship between porosity, permeability, and oil-water displacement radius. By comprehensively utilizing methods such as thin section observation, fluid inclusion petrographic observation, homogenization temperature testing, and burial history analysis, the sequence of diagenesis and the periods and corresponding times of oil charging are analyzed to establish a diagenesis-reservoir evolution sequence. Paleophysical evolution is reconstructed through the diagenesis-reservoir evolution sequence to obtain paleoporosity and paleopermeability during the reservoir formation period. The paleodisplacement pressure during the reservoir formation period of each lithology is calculated using the quantitative functional relationship between porosity, permeability, and oil-water displacement radius. Finally, the paleo-blocking oil column height is calculated using the paleodisplacement pressure difference between adjacent lithologies.

[0066] Step 1: Identify lithological types through core observation and thin section image analysis.

[0067] Detailed observation of the rock cores was conducted to identify the locations where abrupt changes in various lithologies occurred. Core samples were taken from two adjacent lithology types, with at least three 2.5cm × 2.5cm × 5cm cylindrical samples taken from each lithology type. Thin sections were then prepared. The long axis of at least 500 particles was measured under the microscope using a polarizing microscope and a Zeiss Axioscope A1 APOL imaging system. The lithology type was accurately determined according to the SY / T 5434-1999 clastic rock particle size classification standard (Table 1) (Table 2).

[0068] Table 1. Grain size classification criteria for clastic rocks

[0069]

[0070] Table 2. Criteria for classifying clastic rock lithological types

[0071]

[0072]

[0073] Step 2: Conduct porosity, permeability, and oil-driven water displacement pressure tests to establish a quantitative functional relationship between porosity, permeability, and oil-driven water breakthrough radius;

[0074] (1) Using the QKY-Ⅱ gas porosity meter and the STY-Ⅱ gas permeability meter, the porosity and permeability of the selected samples were obtained at room temperature and pressure in accordance with the core analysis method of SY / T 5336-2006.

[0075] (2) Using a diagenetic simulation high-temperature and high-pressure displacement system, experimental water was prepared according to the formation water properties of the sample's stratum. The experimental water prepared by drying, vacuuming, and high-pressure saturation of the selected sample was placed into the high-temperature and high-pressure displacement system. The formation temperature and formation pressure of the sample's stratum were set, crude oil was injected, and oil-water displacement experiments were carried out. The penetration pressure and penetration time of the two tests were recorded to obtain the two rock sample penetration pressures P1 and P2 and the corresponding penetration times t1 and t2. The rock sample penetration pressure and penetration time obtained from the two tests were substituted into the Poisson equation (Formula 1) to obtain the oil-water displacement pressure value P0 of the rock sample. Then, the oil-water breakthrough radius Rt was calculated using Formulas 2 and 3.

[0076] P0=(P2t2-P1t1) / (t2-t1) (Formula 1)

[0077] Rt=2 cosθ / P0 (Formula 2)

[0078] σ=40.5*T0 -0.149 (Formula 3)

[0079] P0: Oil-driven water displacement pressure, MPa; P1: Penetration pressure 1, MPa; P2: Penetration pressure 2, MPa; t1: Penetration time 1, min; t2: Penetration time 2, min; Rt: Oil-driven water breakthrough radius, μm; : Oil-water interfacial tension, mN / m; θ: Petroleum wetting contact angle, °; T0: Experimental temperature, ℃.

[0080] (3) Perform multiple sets of the above experimental procedures to obtain data on porosity Ф, permeability K and corresponding oil-driven water displacement pressure P0, and calculate (K / Ф). 1 / 2The oil-driven water displacement breakthrough radius Rt is expressed in Excel as (K / Ф). 1 / 2 Let Rt be the x-axis and (K / Ф) be the oil-driven water breakthrough radius Rt. Establish a relationship between Rt and (K / Ф). 1 / 2 Quantitative functional relationship.

[0081] The third step involves conducting petrographic observations of cast thin sections and fluid inclusions, homogenization temperature testing, and burial history analysis to establish a diagenetic-accumulation evolution sequence.

[0082] (1) Using a polarizing microscope and a Zeiss Axioscope A1 APOL imaging system, observe the diagenetic phenomena such as the replacement relationship of authigenic minerals and the dissolution and filling relationship in the cast thin section, and determine the order of occurrence of each diagenetic process.

[0083] (2) Using a Zeiss research-grade optical microscope, we conducted petrographic observations and descriptions of fluid inclusions, including the shape, size, gas-liquid ratio, identification of brine and hydrocarbon inclusions, fluorescence color of hydrocarbon inclusions, host minerals, and symbiotic relationships.

[0084] (3) Select gas-liquid two-phase brine inclusions in the cement and gas-liquid two-phase brine inclusions of hydrocarbon inclusions with different fluorescent colors. According to the industry standard SY / T 6010-2011, use the THMS Linkam-600 hot and cold stage to heat the gas-liquid two-phase brine inclusions to transform the gas-liquid two phases into a single phase and restore the single phase state when the gas-liquid two-phase brine inclusions were formed. The instantaneous temperature at this time is the homogenization temperature of the gas-liquid two-phase brine inclusions.

[0085] (4) The homogenization temperature of the gas-liquid two-phase brine inclusions in the cement represents the formation temperature when the cement precipitates. By projecting the homogenization temperature of the gas-liquid two-phase brine inclusions in the cement onto the burial history map, the formation time of the cementation and the paleoburial depth of each well can be determined.

[0086] (5) The homogenization temperature of gas-liquid two-phase brine inclusions contemporaneous with hydrocarbon inclusions of different fluorescent colors represents the formation temperature during oil charging. By projecting this homogenization temperature onto the burial history map, the oil charging period and its corresponding paleoburial depth can be determined. Combined with the research results of the third step (4), a diagenetic-accumulation evolution sequence can be established.

[0087] Step 4: Porosity Evolution Recovery

[0088] (1) Porosity inversion back stripping under the constraint of diagenetic evolution sequence

[0089] Assuming the diagenetic evolution sequence is compaction - feldspar dissolution - cementation by cement 1 - cementation by cement 2 - cementation by cement 3, the currently measured porosity is... The specific steps for porosity inversion and back-stripping under the constraint of diagenetic evolution sequence are as follows ( Figure 2 ):

[0090] ① Using computer image analysis technology, the area percentage (S) of cementitious material 1 in the thin film of the casting is quantitatively calculated. j1 ,%), cementitious material 2 area percentage (S) j2 ,%), cementitious material area percentage (S) j3 %, and the percentage of secondary pore area due to feldspar dissolution (S) spf , %).

[0091] ② Use Formula 4 (according to Wang Yanzhong et al., 2013) to convert the area percentage (S, %) into the corresponding volume percentage. cementitious material 1 volume percentage cementitious material 2 volume percentage cementitious material 3% by volume Secondary pore volume percentage in feldspar dissolution

[0092]

[0093] ③ Using the diagenetic evolution sequence as a constraint, starting from the last diagenetic stage, the back-exfoliation porosity at the beginning (end) of each diagenetic stage is restored, thereby obtaining the back-exfoliation porosity at each paleoburial depth. Figure 2 ).

[0094]

[0095] b1 and All values ​​represent current porosity (%); b5, b4, b3, and b2 represent the inverted peeling porosity (%) corresponding to the completion of stages A, B, C, and D, respectively.

[0096] (2) Perform compaction correction to restore the true porosity evolution.

[0097] Different lithological samples were selected from various depths, with normal formation pressure, cement area percentage less than 5%, and secondary pore area percentage of dissolution origin less than 2%. Porosity-depth relationship diagrams were established for different lithologies, i.e., porosity normal compaction evolution charts. Using these charts, the original porosity of different lithologies and the smaller porosity under compaction at each diagenetic stage were obtained. Subsequently, compaction correction was performed on the porosity inversion and stripping under the constraint of the diagenetic evolution sequence to restore the true porosity evolution. Figure 2 The compaction correction process involves two scenarios:

[0098] ① When the volume percentage of cementitious material is less than the current porosity, the cementitious material occupies less than half of the existing pore space. The cementitious material does not affect the normal compaction of the pores. Compaction correction is carried out according to the normal compaction evolution chart of porosity.

[0099] Compaction reduces total porosity:

[0100]

[0101] Stage A compaction reduces porosity: A 压 =a6-a5

[0102] (Formula 11)

[0103] Stage B compaction reduces porosity: B 压 =a5-a4

[0104] (Formula 12)

[0105] Stage C compaction reduces porosity: C 压 =a4-a3

[0106] (Formula 13)

[0107] Stage D compaction reduces porosity: D 压 =a3-a2

[0108] (Formula 14)

[0109] Stage E compaction reduces porosity: E 压 =a2-a1

[0110] (Formula 15)

[0111] a6 represents the original porosity, in %; a5, a4, a3, a2, and a1 represent the normal compaction porosity, in %, corresponding to the completion of stages A, B, C, D, and E, respectively; a6, a5, a4, a3, a2, and a1 are read from the porosity normal compaction evolution chart.

[0112] By utilizing the compaction effect at each stage to reduce porosity, compaction correction is performed on the porosity inversion back stripping under the constraint of the diagenetic evolution sequence to obtain the true porosity evolution.

[0113]

[0114] c2 = b2 + E 压 (Formula 17)

[0115] c3 = b3 + E 压 +D 压 (Formula 18)

[0116] c4 = b4 + E 压 +D 压 +C 压 (Formula 19)

[0117] c5 = a5 = b5 + E 压 +D 压 +C 压 +B 压 (Formula 20)

[0118] c5, c4, c3, c2, and c1 represent the actual porosity after the completion of stages A, B, C, D, and E, respectively (%).

[0119] ② When the main cementing process occurs and the volume percentage of the cemented material exceeds the porosity, the cementing inhibits compaction, and compaction correction cannot be directly performed using the normal porosity compaction evolution chart. In this case, the total porosity reduction after the main cementing process is allocated according to the proportion of porosity reduction at each stage on the normal porosity compaction evolution chart to determine the compaction porosity correction amount for each diagenetic stage. For example, after cementation of cement 1 in stage C, the volume percentage of cement 1 is greater than that of c3, and in stage D... 压 and E 压 The method for obtaining it is as follows:

[0120]

[0121] D 压 / E 压 = (a3-a2) / (a2-a1) (Formula 22)

[0123] Using formulas 21 and 22, we can solve the system of two linear equations in two variables to calculate D. 压 and E 压 Then, using formulas 16, 17, 18, 19, and 20, compaction correction is performed on the porosity inversion back-stripping under the constraint of the diagenetic evolution sequence to obtain the true porosity evolution.

[0124] Step 5: Penetration Evolution Recovery

[0125] (1) Classify the planar pore structure types and establish the porosity-permeability functional relationship for each pore structure type.

[0126] Computer image analysis technology was used to quantitatively calculate the current pore area percentage S0 and average pore radius in the cast thin section. The pore area percentage and average pore radius were used to classify the planar pore structure type, and the exponential function relationship between K / Φ and K for different planar pore structure types of lithology was fitted.

[0127] (2) Inversion and back-exfoliation of planar pore structure under the constraint of diagenetic evolution sequence

[0128] Similarly assuming the diagenetic evolution sequence is compaction - feldspar dissolution - cementation by cement 1 - cementation by cement 2 - cementation by cement 3, the specific steps for planar pore structure inversion and back-exfoliation under the constraint of the diagenetic evolution sequence are as follows:

[0129] Constrained by the diagenetic evolution sequence, the process begins with back-exfoliation from the last diagenetic stage to reconstruct the start (end) times of each diagenetic stage. Figure 2 The planar porous structure is restored at this stage by equal area.

[0130] Stage E cementitious material 3 at the end of cementation (now) total pore area percentage S b1 =S0(Formula 23)

[0131] Stage D cementitious material 2 cementation end percentage of total pore area S b2 =S0+S j3 (Formula 24)

[0132] Stage C cement 1: Percentage of total pore area at the end of cementation (S) b3 =S0+S j3 +S j2 (Formula 25)

[0133] Stage B: Percentage of total pore area at the end of feldspar dissolution (S) b4 =S0+S j3 +S j2 +S j1 (Formula 26)

[0134] The percentage of total pore area S at the end of stage A rock formation b5 =S0+S j3 +S j2 +S j1 -S spf (Formula 27)

[0136] (3) Correct the pore area loss due to compaction and restore the evolution of the true planar pore structure.

[0137] ① Use Formula 4 to deduce the percentage of the actual pore area at each stage.

[0138] Percentage of true total pore area at the start of stage A: S c6 =0.3968c6 1.182 (Formula 28)

[0139] Percentage of actual total pore area at the start of stage B: S c5 =0.3968c5 1.182 (Formula 29)

[0140] Percentage of true total pore area at the start of stage C: S c4 =0.3968c4 1.182 (Formula 30)

[0141] Percentage of true total pore area at the start of stage D: S c3 =0.3968c3 1.182 (Formula 31)

[0142] Percentage of true total pore area at the start of stage E: S c2 =0.3968c2 1.182 (Formula 32)

[0143] Percentage of true total pore area at the end of stage E: S c1 =S0

[0144] (Formula 33)

[0145] ②Draw diagrams to reconstruct the true planar pore structure before each stage of compaction.

[0146] Let the field of view (a) at the end of stage E have a length of X, μm and a width of Y, μm. Let the field of view (b) at the beginning of recovery stage E have a length of X + ΔX, μm and a width of Y + ΔY, μm; where ΔX is the change in the length of the field of view after recovery, μm; and ΔY is the change in the width of the field of view after recovery, μm. The area reduced by compaction from the beginning to the end of stage E is E. 面压 (Formula 34), μm 2 .

[0147] E 面压 = (X + ΔX) * (Y + ΔY) * S c2 -X*Y*S b1

[0148] (Formula 34)

[0149] During the restoration process, following the principle that "the aspect ratio of the field of view remains unchanged before and after restoration," we have X / Y = (X + ΔX) / (Y + ΔY).

[0150] (Formula 35)

[0151] Solving the system of equations 34 and 35 yields ΔX and ΔY.

[0152] After obtaining ΔX and ΔY, the bottom left particle remains stationary, while the other particles move proportionally to the right and upward. The horizontal distance from the center of each particle to the leftmost point is D. h Then the particle center needs to move a distance ΔD to the right. h =ΔX*D h / X; The distance from the center of the particle longitudinally to the bottommost side is D. zThen the particle center needs to move upward a distance ΔD z =ΔY*D z / Y.

[0153] Based on the planar pore structure diagram at the beginning of recovery stage E, the planar pore structure diagrams at the beginning of stage D, stage C, stage B, and stage A are sequentially recovered using the above method. Using image analysis technology, the percentage of pore area and pore radius of the planar pore structure diagrams at each stage are quantitatively calculated to determine the planar pore structure type.

[0154] (4) Using porosity and permeability functions, the permeability evolution can be recovered.

[0155] Based on the determination of the planar pore structure type in step (3), the permeability during geological history is obtained by using the exponential function relationship between K / Φ and K of reservoirs with different planar pore structure types, and the permeability evolution curve during geological history is established.

[0156] Step 6: Calculate the height of the ancient oil-bearing column based on the ancient displacement pressure difference.

[0157] (1) Calculate the paleoporosity and paleopermeability during the hydrocarbon accumulation period.

[0158] By using the evolution curves of porosity and permeability, the paleoporosity and paleopermeability of the oil reservoir during the oil reservoir charging period and its corresponding paleoburial depth, we can obtain the oil reservoir charging period's paleoporosity and paleopermeability.

[0159] (2) Calculate the oil-driven water displacement pressure during the reservoir formation period.

[0160] Using paleoporosity and paleopermeability data, (K / Ф) 1 / 2 The linear relationship between the oil-flooding breakthrough radius Rt and the reservoir formation period is used to obtain the oil-flooding breakthrough radius Rt; the paleo-oil-flooding displacement pressure during the reservoir formation period is obtained using formulas 2 and 3.

[0161] (3) Calculate the height of the paleo-suppression oil column in adjacent lithologies during the hydrocarbon accumulation period.

[0162] The height of the ancient plugging oil column in adjacent lithology during the hydrocarbon accumulation period was obtained using Formula 36.

[0163] Z omax =ΔP / (ρ w -ρ o (Formula 36)

[0164] Maximum oil column height: Z omax m; water density: ρ w =1Kg / m 3 Oil density: ρ o =0.9Kg / m 3 Gravitational constant: g = 9.8 m / s² 2Displacement pressure difference between adjacent lithologies: ΔP, MPa.

[0165] Example 2

[0166] Taking the nearshore underwater fan sandstone and conglomerate lithological trap in the upper subsection of the Sha-4 sub-section of the steep slope zone in the northern part of the ×× depression of the ×× oilfield as an example, the specific implementation plan of this invention is explained.

[0167] Step 1: Identify lithological types through core observation and thin section image analysis.

[0168] Detailed observation of the core samples was conducted to identify locations where abrupt changes in various lithologies occurred. Core samples were taken from two adjacent lithology types, with at least three 2.5cm × 2.5cm × 5cm cylindrical samples taken from each lithology type and then ground into thin sections. Using a polarizing microscope and a Zeiss Axioscope A1 APOL imaging system, the long axis of at least 500 particles was measured. According to the SY / T 5434-1999 standard for grain size classification of clastic rocks (Table 1) and the standard for lithology classification of clastic rocks (Table 2), nine types of lithology were identified in the nearshore underwater fan sandstone and conglomerate lithology trap of the upper subsection of Sha-4 in the steep slope zone of the northern part of the ×× depression of the ×× oilfield: medium conglomerate, fine conglomerate, gravelly sandstone, pebbly sandstone, coarse sandstone, medium sandstone, fine sandstone, siltstone, and mudstone.

[0169] Step 2: Conduct porosity, permeability, and oil-driven water displacement pressure tests to establish a quantitative functional relationship between porosity, permeability, and the breakthrough radius of oil-driven water.

[0170] (1) Using the QKY-Ⅱ gas porosity meter and STY-Ⅱ gas permeability meter, the porosity and permeability of the selected samples were obtained at room temperature and pressure according to the core analysis method of SY / T 5336-2006 (Table 3).

[0171] Table 3 Sample Test Data Recording Table

[0172]

[0173]

[0174] (2) Using a diagenetic simulation high-temperature and high-pressure displacement system, experimental water was prepared according to the formation water properties of the stratum where sample 1 is located at 3782.7m (Table 4). The experimental water prepared by drying, vacuuming, and high-pressure saturation of the selected sample was placed into the high-temperature and high-pressure displacement system. The formation temperature (141.68℃) and formation pressure (48.7MPa) of the stratum where sample 1 is located were set (Table 4). Crude oil was injected (Table 4) and oil-water displacement experiments were carried out. The penetration pressure and penetration time of the two tests were recorded to obtain the two rock sample penetration pressures P1 and P2 and the corresponding penetration times t1 and t2. The rock sample penetration pressure and penetration time obtained from the two tests were substituted into the Poisson equation (Formula 1) to obtain the oil-water displacement pressure value of 1.99MPa. Then, the oil-water breakthrough radius of 0.02μm was calculated by Formula 2 and Formula 3 (Table 3).

[0175] (3) Perform multiple sets of the above experimental procedures to obtain data on porosity Ф, permeability K and corresponding oil-driven water displacement pressure P0 (Table 3), and calculate (K / Ф). 1 / 2 The oil-driven water displacement breakthrough radius Rt is expressed in Excel as (K / Ф). 1 / 2 Let Rt be the x-axis and (K / Ф) be the oil-driven water breakthrough radius Rt. Establish a relationship between Rt and (K / Ф). 1 / 2 Quantitative exponential function relationship ( Figure 3 ).

[0176] Table 4. Record of Formation Temperature, Formation Pressure, Formation Water, and Petroleum Properties

[0177]

[0178]

[0179] Step 3: Conduct petrographic observations of cast thin sections and fluid inclusions, perform homogenization temperature testing, and analyze burial history to establish a diagenetic-accumulation evolution sequence.

[0180] (1) Using a polarizing microscope and a Zeiss Axioscope A1 APOL imaging system, we observed the diagenetic phenomena such as the replacement relationship and dissolution-filling relationship of authigenic minerals in the thin sections of the casting. Typical replacement phenomena in the nearshore underwater fan sandstone and conglomerate lithological traps of the upper subsection of Sha-4 in the steep slope zone of the northern part of the ×× depression of the ×× oilfield include: calcite replacing quartz overgrowth (a), dolomite replacing quartz overgrowth (b), ferrodolomite replacing quartz overgrowth (b), calcite replacing dolomite (c), ferrodolomite replacing ferrocalcite (d), and ferrocalcite replacing calcite (e). In addition, calcite cement fills the secondary pores generated by feldspar dissolution (f). The silica required for the formation of quartz overgrowth comes from the silica generated by feldspar dissolution. Therefore, the time of feldspar dissolution is similar to that of quartz overgrowth, but earlier than the time of calcite cement formation.

[0181] The chronological order of the various diagenetic processes was determined as follows: compaction → feldspar dissolution / quartz enlargement → dolomite cementation → calcite cementation → ferrocalcite cementation → ferrodolithite cementation.

[0182] (2) Using a Zeiss research-grade optical microscope, petrographic observation and description of fluid inclusions were carried out. The petrographic and fluorescence characteristics of inclusions developed in cements such as quartz, calcite, ferrocalcite, dolomite, and ferrodolithite were observed. In the nearshore underwater fan sandstone and conglomerate lithological traps of the steep slope belt in the northern part of the ×× Depression of the ×× Oilfield, the morphology of gas-liquid two-phase brine inclusions is mainly elliptical, elongated, and triangular, with a size between 3-5 μm. The gas part is transparent spherical and constantly sloshing in the liquid environment, without fluorescence (a, b, c, d); two types of fluorescent oil inclusions are developed, one stage is yellow fluorescent oil inclusions (a, b), and the other stage is blue fluorescent oil inclusions (c, d). Oil inclusions often develop in strings in quartz fracture healing fractures. Oil inclusions and gas-liquid two-phase brine inclusions can develop simultaneously in the same quartz fracture healing fracture. Their formation time and homogenization temperature are the same or similar, and they are the same inclusion assemblage.

[0183] (3) Select gas-liquid two-phase brine inclusions from cements such as quartz, dolomite, calcite, ferrocalcite, and ferrodolithite, along with gas-liquid two-phase brine inclusions that are contemporaneous with yellow fluorescent hydrocarbon inclusions and blue fluorescent hydrocarbon inclusions. According to the industry standard SY / T6010-2011, use a THMS Linkam-600 hot and cold stage to heat the gas-liquid two-phase brine inclusions to transform the gas-liquid two-phase into a single phase, restoring the single-phase state at the time of formation of the gas-liquid two-phase brine inclusions. The instantaneous temperature at this time is the homogenization temperature of the gas-liquid two-phase brine inclusions. The temperature measurement data of the inclusions are shown in Table 5.

[0184] Table 5. Homogenization temperature data of lithological trap inclusions in nearshore underwater fan sandstone and conglomerate in the upper segment of the Sha-4 sub-section of the steep slope zone in the northern part of the ×× depression.

[0185]

[0186] (4) The homogenization temperature of the gas-liquid two-phase brine inclusions in the cement represents the formation temperature when the cement precipitates. The homogenization temperature of the gas-liquid two-phase brine inclusions in cements such as quartz, dolomite, calcite, ferrocalcite, and ferrodolomite is projected onto the burial history map of the well (a). The time of each diagenesis is determined by combining the projections of the burial history maps of each well. The development time of quartz cement is 45.1-43.9 Ma, the development time of calcite cement is 44.0-43.0 Ma, the development time of dolomite cement is 44.2-38.8 Ma, the development time of ferrocalcite cement is 27.9-24.1 Ma, and the development time of ferrodolomite cement is 23.4-15.6 Ma (b). The paleoburial depth of cementation in each well is also determined.

[0187] (5) The homogenization temperature of gas-liquid two-phase brine inclusions contemporaneous with the yellow fluorescent hydrocarbon inclusions and the blue fluorescent hydrocarbon inclusions was projected onto the burial history map to determine that the first phase of yellow fluorescent oil inflow occurred between 41.1 and 25.15 Ma, and the second phase of blue fluorescent oil inflow occurred between 13.8 Ma and the present. Combined with the research results of the third step (4), the diagenetic-accumulation evolution sequence was finally established: compaction → feldspar dissolution / quartz enlargement → dolomite cementation → first phase of yellow fluorescent oil inflow → calcite cementation → ferrocalcite cementation → ferrodolithic cementation → second phase of blue fluorescent oil inflow.

[0188] Step 4: Porosity Evolution Recovery

[0189] (1) Porosity inversion back stripping under the constraint of diagenetic evolution sequence

[0190] Taking the coarse sandstone (sample 1) at 3738.7m in Table 6 as an example

[0191] ① Using computer image analysis technology, the percentage of quartz enlarged edge area S in the cast thin sheet 1 was quantitatively calculated. js =1.43%, calcite area percentage S jf =8.99%, ferrocalcite area percentage S jtf =0.90%, Dolomite area percentage S jb =2.04%, iron dolomite area percentage S jtb =0.40%, percentage of secondary pore area S due to feldspar dissolution spf =0.90% (Table 6). Table 6: Original porosity, area / volume percentage of various cementitious materials, total porosity and secondary porosity area / volume percentage

[0192]

[0193] ② Using Formula 4 (according to Wang Yanzhong et al., 2013), the area percentage was converted into the corresponding volume percentage. The volume percentage of quartz with large side was 3%, calcite was 14%, iron calcite was 2%, dolomite was 4%, iron dolomite was 1%, and the volume percentage of secondary pores formed by feldspar dissolution was 2% (Table 6).

[0194] ③ Using the diagenetic evolution sequence as a constraint, the back-peeling begins from the last diagenetic stage, and the back-peeling porosity at the beginning (end) of each diagenetic stage is restored, thereby obtaining the back-peeling porosity at each paleoburial depth (Table 7 "Back-peeling porosity of chemical diagenesis, %" column).

[0195] Table 7. Porosity Inversion and Stripping Values

[0196]

[0197]

[0198] (2) Perform compaction correction to restore the true porosity evolution.

[0199] Different lithological samples were selected from various depths, with normal formation pressure, cement area percentage less than 5%, and secondary pore area percentage of dissolution origin less than 2%. A porosity-depth relationship diagram was established for different lithologies, i.e., a porosity normal compaction evolution chart. Using this chart, the original porosity of a coarse sandstone sample at 3738.7 m was determined to be 43% (Table 6). Based on the chronological order of diagenesis determined in step three and the type of cement developed in the sample, the evolutionary stages experienced by the sample and the timing of diagenesis were determined. Read the percentage of normal compaction pore volume at the beginning and end of each stage from the normal compaction evolution chart (). The difference between the two is the percentage of pore volume reduced by normal compaction in this stage. Record this in two columns: normal compaction reduction and cumulative normal compaction reduction (Table 7). If normal compaction is developed from 0m to the dolomite cementation stage, then the true porosity at this time = original porosity - percentage of pore volume reduced by normal compaction - percentage of increased quartz volume + secondary porosity from dissolution - percentage of dolomite cement volume = 43% - 19% - 3% + 2% - 4% = 19%. At this time, the cement volume percentage = percentage of increased quartz volume + percentage of dolomite cement volume.

[0200] =3% + 4% = 7%, the volume percentage of cement is less than the actual porosity, which meets the standard that cement does not affect normal compaction; to the calcite cementing stage, if normal compaction is developed, then at this time, the actual porosity = original porosity - percentage of pore volume reduced by normal compaction - percentage of increased quartz volume + secondary porosity from dissolution - percentage of dolomite cement volume - percentage of calcite cement volume = 43% - 21% - 3% + 2% - 4% - 14% = 3%; at this time, the volume percentage of cement = percentage of increased quartz volume + percentage of dolomite cement + percentage of calcite cement volume = 3% + 4% + 14% = 21%, the volume percentage of cement is greater than the actual porosity, so the cement content in the calcite cementing stage has already affected normal compaction. Actual compaction porosity reduction = Original porosity - Current porosity - Cement volume percentage + Secondary porosity = 43% - 1% - (3% + 4% + 14% + 2% + 1%) + 2% = 20%. At the dolomite cementation stage, the actual compaction porosity reduction percentage is 19%. Therefore, the sum of the compaction porosity reduction percentages for the subsequent three stages = Total porosity reduction percentage due to compaction - Cumulative porosity reduction percentage due to compaction after the dolomite cementation stage = 20% - 19% = 1%. Based on the normal compaction ratio of 2:13:2 for the subsequent three stages, allocating 1% of the compaction porosity reduction percentage, the actual compaction porosity reduction percentages for the three stages are 0.12%, 0.76%, and 0.12%, respectively. The actual compaction porosity reduction percentages for each stage are entered into the inversion back-exfoliation porosity column of compaction diagenesis.

[0201] By utilizing the compaction effects at each stage to reduce porosity, compaction correction is applied to the porosity inversion and stripping under the constraint of the diagenetic evolution sequence to obtain the true porosity evolution. The true porosity before the ferrodolomite cementation stage = current porosity + volume percentage of ferrodolomite cement + inversion stripping pore volume percentage of the current stage of compaction diagenesis.

[0202] =1% + 1% + 0.12% = 2.12%; True porosity before the cementation stage of ferrocalcite = True porosity before the cementation stage of ferrodolithite + Volume percentage of ferrocalcite cement + Volume percentage of inverted exfoliated pores from the compaction and diagenesis in this stage

[0203] =2.12% + 2% + 0.76% = 4.88%; True porosity before the calcite cementation stage = True porosity before the ferrocalcite cementation stage + Volume percentage of calcite cement + Volume percentage of inverted exfoliated pores from the compaction and diagenesis in this stage = 4.88% + 14% + 0.12% = 19%; True porosity before the dolomite cementation stage = True porosity before the calcite cementation stage + Volume percentage of dolomite cement + Volume percentage of inverted exfoliated pores from the compaction and diagenesis in this stage = 19% + 4% + 2% = 25%; Quartz enlargement and feldspar dissolution stages The true porosity before the compaction stage = true porosity before the dolomite cementation stage + percentage of quartz enlarged cement volume - percentage of secondary pore volume from feldspar dissolution + percentage of inverted exfoliated pore volume from the compaction diagenesis in this stage = 25% + 3% - 2% + 3% = 29%; the true porosity before the normal compaction stage = true porosity before the quartz enlargement and feldspar dissolution stages + percentage of inverted exfoliated pore volume from the compaction diagenesis in this stage = 29% + 14% = 43%. Based on Table 7, the evolution relationship of porosity over time (burial depth) for a coarse sandstone sample at a depth of 3738.7 m is established. Figure 4 ).

[0204] Step 5: Penetration Evolution Recovery

[0205] (1) Classify the types of planar pore structures and establish the functional relationship between porosity and permeability for each type of pore structure;

[0206] Using computer image analysis technology, the percentage of pore area S0 and the average pore radius in the cast thin sections were quantitatively calculated. Based on pore area percentages of 1%, 3%, 5%, 10%, and 15% and average pore radii of 1μm, 10μm, 20μm, 50μm, and 100μm, the sections were divided into six subcategories: best (Class IA), second best (Class IB), above average (Class IIA), below average (Class IIB), second worst (Class IIIA), and worst (Class IIIB). Using porosity and permeability data, exponential function relationships between K / Φ and K were fitted to lithologies with different planar pore structure types. Figure 5 ).

[0207] (2) Inversion and back-exfoliation of planar pore structure under the constraint of diagenetic evolution sequence

[0208] Constrained by the diagenetic evolution sequence, the back-exfoliation begins from the last diagenetic stage to restore the planar pore structure at the beginning (end) of each diagenetic stage. This stage is an equal-area restoration.

[0209] Percentage of total pore area S at the end of cementation of iron dolomite (currently) b1 =S0=0.4%;

[0210] Percentage of total pore area S at the end of cementation of ferrocalcite b2 =

[0211] S0+S jtb =0.4% + 0.4% = 0.8%;

[0212] Percentage of total pore area S at the end of calcite cementation b3 =

[0213] S0+S jtb +S jtf =0.8% + 0.9% = 1.7%;

[0214] The percentage of total pore area at the end of dolomite cementation (S) b4 =S0+S jtb +S jtf +S jf

[0215] =1.7% + 8.99% = 10.69%;

[0216] Percentage of total pore area at the end of quartz enlargement and feldspar dissolution: S b5 =

[0217] S0+S jtb +S jtf +S jf +S jb =10.69% + 2.04% = 12.73%;

[0218] Percentage of total pore area at the onset of quartz enlargement and feldspar dissolution: S b6 =

[0219] S0+S jtb +S jtf +S jf +S jb +S js -S spf =12.73% + 1.43% - 0.9% = 13.26%.

[0220] Among them, S jtb S jtf S jf S jb S js and S spf These represent the percentages of cemented area of ​​ferrodolomite, ferrocalcite, calcite, dolomite, quartz enlarged edge cemented area, and feldspar dissolved secondary pore area, respectively.

[0221] (3) Correct the pore area loss due to compaction and restore the evolution of the true planar pore structure.

[0222] ① Use Formula 4 to deduce the percentage of the true pore area at each stage (Table 7). Percentage of the true total pore area at the start of compaction: S c7 =0.3968c7 1.182 =33.89%;

[0223] Percentage of true total pore area at the onset of quartz enlargement and feldspar dissolution: S c6

[0224] =0.3968c6 1.182 =21.37%;

[0225] Percentage of true total pore area at the end of quartz enlargement and feldspar dissolution: S c5

[0226] =0.3968c5 1.182 =17.85%;

[0227] Percentage of total actual pore area at the end of dolomite cementation: S c4 =0.3968c4 1.182 =12.90%;

[0228] Percentage of true total pore area at the end of calcite cementation: S c3 =0.3968c3 1.182 =2.59%;

[0229] Percentage of total actual pore area at the end of cementation of ferruginous calcite: S c2 =0.3968c2 1.182 =0.96%;

[0230] Percentage of total actual pore area at the end of cementation of iron-white dolomite (currently): S c1 =S0=0.4%.

[0231] c2, c3, c4, c5, c6, and c7 represent the actual total porosity at the end of cementation of ferrocalcite, the actual total porosity at the end of cementation of calcite, the actual total porosity at the end of cementation of dolomite, the actual total porosity at the end of quartz enlargement and feldspar dissolution, the actual total porosity at the beginning of quartz enlargement and feldspar dissolution, and the actual total porosity at the beginning of compaction, respectively.

[0232] ②Draw diagrams to reconstruct the true planar pore structure before each stage of compaction.

[0233] Taking the coarse sandstone sample at 3738.7m as an example, the calculations of ΔX and ΔY in the cementation stage of ferrodolomite are as follows:

[0234] The current field of view has a length X = 1230 μm and a width Y = 990 μm; let the restored field of view have a length of X + ΔX and a width of Y + ΔY, then the area reduced by compaction is: Sy = (X + ΔX) * (Y + ΔY) * S c2 -X*Y*S b1 X + ΔX = X / Y * (Y + ΔY)

[0235] Substituting X = 1230 μm and Y = 990 μm, we calculate (Y + ΔY) = 995.72 μm and (X + ΔX) = 1237.11 μm. ΔX and ΔY are 7.11 μm and 5.73 μm, respectively. The field of view length and width and the corresponding ΔX and ΔY for each stage are obtained in the same way (Table 8).

[0236] Table 8. Length and width of the field of view at each stage of the planar pore structure inversion and back-peeling.

[0237]

[0238] After obtaining ΔX and ΔY, the bottom left particle remains stationary, while the other particles move proportionally to the right and upward. The horizontal distance from the center of each particle to the leftmost point is D. h Then the particle center needs to move a distance ΔD to the right. h =ΔX*D h / X; The distance from the center of the particle longitudinally to the bottommost side is D. z Then the particle center needs to move upward a distance ΔD z =ΔY*D z / Y, reconstruct the pore throat planar feature map for each stage, as shown in a for the particle center, D h =502μm, D z =202μm, then ΔD h =ΔX*D h / X=7.11*502 / 1230=2.9μm; ΔD z =ΔY*D z / Y

[0239] =5.72*202 / 990 = 1.2μm, then the position of this particle in 14b is D. h =502 + 2.9 = 504.9 μm, D z =202+1.2=203.2μm.

[0240] The current field of view is a type IIIB pore structure (a). After restoring the field of view before cementation of iron dolomite (b), iron calcite (c), calcite (d), dolomite (e), quartz enlargement and feldspar dissolution (f), and normal compaction (g) in sequence using the above method, the planar pore structures are, in sequence, type IIIB, type IIIB, type IIIA, type IB, type IB, type IA, and type IA.

[0241] (4) Using porosity and permeability functions, the permeability evolution can be recovered.

[0242] The permeability was recovered using the exponential function relationship between K / Φ and K for reservoirs with different planar pore structure types. The permeability before cementation of ferrodolomite was recovered using the function relationship of type IIIB planar pore structure; the permeability before cementation of ferrocalcite was recovered using the function relationship of type IIIA planar pore structure; the permeability before cementation of calcite and dolomite was recovered using the function relationship of type IB planar pore structure; and the permeability before quartz enlargement, feldspar dissolution, and normal compaction was recovered using the function relationship of type IA planar pore structure (Table 9). Permeability evolution curves for geological history were established. Figure 4 ).

[0243] Table 9. Types of planar pore structure, porosity, and permeability at each stage of permeability inversion and back-stripping.

[0244] stage Depth, m Time, Ma Pore ​​structure type True porosity, % True penetration rate, mD Primitive sediments 0 46.0 Type IA 43.00 820577.6983 Normal compaction 0-1000 46.0-45.1 Type IA 29.00 7971.24438 Quartz enlargement and feldspar dissolution 1000-1300 45.1-43.9 Type IB 25.00 7.6788 Dolomite cementation 1300-1500 44.2-38.8 Type IB 19.00 4.2504 calcite cementation 1500-1700 44.0-43.0 Type IIIA 4.88 0.0269 Iron cube calcite cementation 1700-3200 27.9-24.1 Type IIIB 2.12 0.0082 Iron dolomite cementation 3200-3500 23.4-0.0 Type IIIB 1.00 0.0022

[0245] Step 6: Calculate the height of the ancient oil-bearing column based on the ancient displacement pressure difference.

[0246] (1) Calculate the paleoporosity and paleopermeability during the hydrocarbon accumulation period.

[0247] Taking the adjacent gravelly sandstone / coarse sandstone assemblage in the nearshore underwater fan sandstone and conglomerate lithological trap of the upper sub-section of the Sha-4 sub-section in the steep slope zone of the northern part of the ×× depression of the ×× oilfield as an example, the first phase of yellow fluorescent oil charging occurred between 41.1 and 25.15 Ma. Taking a certain time of 32 Ma during the reservoir formation period as an example, the height of the paleo-suppression oil column was calculated, and the evolution of physical properties of the gravelly sandstone and coarse sandstone during the geological history was reconstructed using the fourth and fifth steps. Figure 4 , Figure 6 By utilizing porosity and permeability evolution curves, the paleoporosity and paleopermeability of the oil accumulation period and its corresponding paleoburial depth were obtained. Figure 4 The reactive coarse sandstone has a porosity of 2.5% and a permeability of 0.011 mD at 32 Ma. Figure 6 The reactant gravelly sandstone has a porosity of 6% and a permeability of 0.035 mD at 32 Ma.

[0248] (2) Calculate the oil-driven water displacement pressure during the reservoir formation period.

[0249] Using paleoporosity and paleopermeability data, (K / Ф) 1 / 2 The linear relationship between the oil-water flooding breakthrough radius Rt and the reservoir formation radius Rt is used to obtain the oil-water flooding breakthrough radius Rt during the reservoir formation period. Figure 3 The breakthrough radius for oil flooding in the coarse sandstone was found to be 0.0048 μm, and the breakthrough radius for oil flooding in the gravelly sandstone was found to be 0.0051 μm. Using formulas 2 and 3, the paleooil flooding displacement pressure during the reservoir formation period was obtained: the breakthrough pressure for oil flooding in the coarse sandstone was 6.998 MPa, and the breakthrough pressure for oil flooding in the gravelly sandstone was 6.587 MPa.

[0250] (3) Calculate the height of the paleo-suppression oil column in adjacent lithologies during the hydrocarbon accumulation period.

[0251] Substituting the above data into Formula 36, ​​we can obtain the ancient plugging oil column height of the adjacent coarse sandstone and gravelly sandstone during the reservoir formation period as 40.278m.

[0252] Beneficial effects: This invention solves the problem of quantitatively calculating the height of adjacent lithological paleo-blocking oil columns in lithological traps during geological history, and provides an effective method for studying the paleo-blocking capacity of lithological traps during oil accumulation, which is of great significance in guiding the exploration and development of lithological oil reservoirs.

[0253] The above specific embodiments further illustrate the purpose, technical solution, and beneficial effects of the present invention. It should be understood that the above are merely specific embodiments of the present invention and are not intended to limit the scope of protection of the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.

Claims

1. A method for determining the height of adjacent lithological paleo-suppression oil columns, characterized in that, The height determination method includes: Step S1: Identify the lithology type based on core observation and thin section image analysis of the cast body; Step S2: Conduct porosity, permeability, and oil-driven water displacement pressure tests to establish a quantitative functional relationship between porosity, permeability, and oil-driven water breakthrough radius; Step S3: Conduct petrographic observations of cast thin sections and fluid inclusions, perform homogenization temperature tests, and analyze burial history to establish a diagenetic-accumulation evolution sequence; Step S4: Perform porosity evolution reconstruction to obtain paleoporosity and paleopermeability during the hydrocarbon accumulation period; Step S5: Perform permeability evolution recovery to obtain ancient displacement pressure; Step S6: Calculate the height of the ancient oil-bearing column based on the difference in ancient displacement pressure.

2. The method for determining the height of adjacent lithological paleo-suppression oil columns according to claim 1, characterized in that, Step S1: Identifying lithology types based on core observation and thin section image analysis of the cast body specifically includes: The rock core was used to identify the locations where various lithologies changed abruptly, and rock core samples were taken from two adjacent lithology types. The long axis is measured to determine the lithology according to the grain size classification standard for clastic rocks.

3. The method for determining the height of adjacent lithological paleopole oil columns according to claim 1, characterized in that, Step S2: Conducting porosity, permeability, and oil-driven water displacement pressure tests to establish a quantitative functional relationship between porosity, permeability, and oil-driven water breakthrough radius specifically includes: For each lithological type, samples were taken for porosity, permeability, and oil-driven water displacement pressure tests to obtain porosity, permeability, and oil-driven water displacement pressure data, and to establish a quantitative functional relationship between porosity, permeability, and oil-driven water breakthrough radius.

4. The method for determining the height of adjacent lithological paleopole oil columns according to claim 1, characterized in that, Step S3: Conducting petrographic observations and homogenization temperature tests on cast thin sections and fluid inclusions, and analyzing burial history to establish a diagenetic-accumulation evolution sequence specifically includes: By comprehensively utilizing methods such as thin section observation of cast bodies, petrographic observation of fluid inclusions, homogenization temperature testing, and burial history analysis, the chronological sequence of diagenesis and the periods and corresponding times of oil charging were analyzed to establish a diagenetic-reservoir evolution sequence.

5. The method for determining the height of adjacent lithological paleo-plugging oil columns according to claim 1, characterized in that, Step S4: Porosity evolution restoration specifically includes: restoring paleophysiological evolution through diagenesis-reservoir formation evolution sequence to obtain paleoporosity and paleopermeability during reservoir formation.

6. The method for determining the height of adjacent lithological paleoplucking oil columns according to claim 1, characterized in that, Step S5: Permeability evolution recovery to obtain ancient displacement pressure specifically includes: By utilizing the quantitative functional relationship between porosity, permeability, and the oil-driven water breakthrough radius, the paleodisplacement pressure during the hydrocarbon accumulation period of each lithology was determined.

7. The method for determining the height of adjacent lithological paleo-plugging oil columns according to claim 1, characterized in that, Step S6: Calculating the ancient oil-bearing column height based on the difference in ancient displacement pressures specifically includes: By using the evolution curves of porosity and permeability, the ancient porosity and ancient permeability of the oil-filling and reservoir-forming period and its corresponding ancient burial depth were obtained. Using paleoporosity and paleopermeability data, (K / Ф) 1 / 2 The linear relationship between the oil-water flooding breakthrough radius Rt and the reservoir formation radius Rt is used to obtain the oil-water flooding breakthrough radius Rt during the reservoir formation period. Calculate the ancient oil displacement pressure during the reservoir formation period; The height of the ancient plugging oil column in adjacent lithology during the hydrocarbon accumulation period was obtained using Formula 36. Z omax =ΔP / (ρ w -ρ o (Formula 36) Maximum oil column height: Z omax m; water density: ρ w =1Kg / m 3 Oil density: ρ o =0.9Kg / m 3 Gravitational constant: g = 9.8 m / s² 2 Displacement pressure difference between adjacent lithologies: ΔP, MPa.

8. The method for determining the height of adjacent lithological paleopustration oil columns according to claim 1, characterized in that, Step S2: Conducting porosity, permeability, and oil-driven water displacement pressure tests to establish a quantitative functional relationship between porosity, permeability, and oil-driven water breakthrough radius specifically includes: Using a gas porosimeter and a gas permeability meter, the porosity and permeability of selected samples were obtained at room temperature and pressure according to the core analysis method. Using a diagenetic simulation high-temperature and high-pressure displacement system, experimental water was prepared according to the formation water properties of the sample's stratum. The experimental water prepared by drying, vacuuming, and high-pressure saturation of the selected sample was placed into the high-temperature and high-pressure displacement system. The formation temperature and formation pressure of the sample's stratum were set, crude oil was injected, and oil-water displacement experiments were carried out. Record the penetration pressure and penetration time twice to obtain the two rock sample penetration pressures P1 and P2 and the corresponding penetration times t1 and t2. Substitute the rock sample penetration pressure and penetration time obtained from the two tests into the Poisson equation (Formula 1) to obtain the oil-displacement pressure value P0 of the rock sample. Calculate the oil-displacement water breakthrough radius Rt using Formulas 2 and 3. P0=(P2t2-P1t1) / (t2-t1) (Formula 1) Rt=2 cosθ / P0 (Formula 2) σ=40.5*T0 -0.149 (Formula 3) P0 is the oil-driven water displacement pressure, MPa; P1 is the penetration pressure 1, MPa; P2 is the penetration pressure 2, MPa; t1 is the penetration time 1, min; t2 is the penetration time 2, min; Rt is the oil-driven water breakthrough radius, μm; σ is the oil-water interfacial tension, mN / m; θ is the petroleum wetting contact angle, °; T0 is the experimental temperature, ℃. Multiple sets of the above experimental procedures were performed to obtain data on porosity Ф, permeability K, and the corresponding oil-driven water displacement pressure P0, and the (K / Ф) ratio was calculated. 1 / 2 The oil-driven water displacement breakthrough radius Rt is expressed in Excel as (K / Ф). 1 / 2 Let Rt be the x-axis and (K / Ф) be the oil-driven water breakthrough radius Rt. Establish a relationship between Rt and (K / Ф). 1 / 2 Quantitative functional relationship.

9. The method for determining the height of adjacent lithological paleoplucking oil columns according to claim 1, characterized in that, Step S3: Conducting petrographic observations and homogenization temperature tests on cast thin sections and fluid inclusions, and analyzing burial history to establish a diagenetic-accumulation evolution sequence specifically includes: Using a polarizing microscope and camera system, we observed the diagenetic phenomena of authigenic mineral replacement and dissolution-filling relationships in thin sections of cast bodies to determine the chronological order of each diagenetic process. Using optical microscopy, we conducted petrographic observations and descriptions of fluid inclusions; Two-phase brine inclusions of gas and liquid in cement were selected, along with two-phase brine inclusions of gas and liquid with different fluorescent colors of hydrocarbon inclusions. According to industry standards, the two-phase brine inclusions were heated using a hot and cold stage to transform the two phases into a single phase, restoring the single-phase state at the time of the formation of the two-phase brine inclusions. The instantaneous temperature was the homogenization temperature of the two-phase brine inclusions. The homogenization temperature of gas-liquid two-phase brine inclusions in cement represents the formation temperature during cement precipitation. By projecting the homogenization temperature of gas-liquid two-phase brine inclusions in cement onto the burial history map, the formation time of cementation and the paleoburial depth of each well can be determined. Homogenization temperatures of gas-liquid two-phase brine inclusions contemporaneous with hydrocarbon inclusions of different fluorescent colors represent formation temperatures during oil charging. By projecting homogenization temperatures onto the burial history map, the oil charging period and its corresponding paleoburial depth can be determined. Combined with the formation time of cementation and the paleoburial depth in each well, a diagenetic-reservoir evolution sequence can be established.

10. The method for determining the height of adjacent lithological paleopustration oil columns according to claim 9, characterized in that, The petrographic observation and description of fluid inclusions includes the identification of fluid inclusion shape, size, gas-liquid ratio, brine inclusions and hydrocarbon inclusions, fluorescence color of hydrocarbon inclusions, host minerals, and paragenetic assemblage relationships.

11. A system for determining the height of adjacent lithological paleo-suppressed oil columns, employing the method for determining the height of adjacent lithological paleo-suppressed oil columns as described in any one of claims 1-10, characterized in that, The height determination system includes: The lithology type identification module is used to identify lithology types based on core observation and thin section image analysis of cast bodies; The quantitative functional relationship establishment module is used to conduct porosity, permeability and oil-driven water displacement pressure tests, and to establish a quantitative functional relationship between porosity, permeability and oil-driven water breakthrough radius; The evolutionary sequence establishment module is used for petrographic observation of cast thin sections and fluid inclusions, homogenization temperature testing, and burial history analysis to establish a diagenetic-accumulation evolutionary sequence. The porosity evolution recovery module is used to recover porosity evolution and obtain paleoporosity and paleopermeability during the hydrocarbon accumulation period. The permeability evolution recovery module is used to recover permeability evolution and obtain ancient displacement pressures; The ancient oil-bearing column height calculation module is used to calculate the ancient oil-bearing column height based on the difference in ancient displacement pressure.

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