A method for predicting the oil-bearing boundary of traps in normal pressure area of a faulted basin

Abstract

The present application relates to the technical field of oil and gas field exploration and development, in particular to a method for predicting the oil-bearing property limit of traps in normal pressure area of faulted basin. The present application is aimed at the oil reservoirs in normal pressure area of faulted basin. On the basis of determining the distribution range of normal pressure area, the present application determines the main controlling factors of reservoir formation with high correlation degree with the oil-bearing saturation of traps by analyzing the correlation between the factors of reservoir formation in normal pressure area and the oil-bearing saturation of traps. The present application establishes the limit prediction chart of oil-bearing property based on the correlation between the main controlling factors of reservoir formation in different oil-bearing property traps such as water layer, oil-water layer and pure oil layer, so as to realize the prediction of the oil-bearing property limit of traps. The present application has strong operability, effectively solves the problem that the prediction of the oil-bearing property limit of oil reservoirs in normal pressure area of faulted basin is inaccurate or incomplete and cannot be predicted before drilling in the prior art, and realizes the effect of accurately predicting the oil-bearing property limit of traps in normal pressure area.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of oil and gas field exploration and development, and particularly relates to a method for predicting the oil-bearing property limit of traps in normal-pressure areas of a faulted basin. BACKGROUND

[0002] The oil-bearing property of an oil and gas trap includes fullness and oil saturation. The fullness refers to the degree to which the entire trap is filled with oil and gas, and the oil saturation refers to the proportion of oil and gas in the part of the trap filled with oil and gas excluding bound water. At present, the fullness of a trap is mainly predicted by using sample data of independent variables that affect the fullness of the trap, analyzing the correlation between the dependent variable and the independent variable, establishing a fullness prediction model, and then predicting the fullness of the trap. However, the oil and gas proportion of the part filled with oil and gas cannot be determined. Some traps are filled with oil and gas, but the content of bound water is high, resulting in a low oil saturation of the trap and poor development effect.

[0003] Therefore, it is of great significance to determine the oil-bearing property limit of an oil and gas trap by using the oil saturation for the classification of the quality of an oil reservoir. The oil saturation of a good-quality oil reservoir is more than 50%, which belongs to a pure oil layer and is characterized by pure oil production during development. The oil saturation of a substandard-quality oil reservoir is 10%-50%, which belongs to an oil-water layer and is characterized by oil-water production during development. The oil saturation of a poor-quality oil reservoir is less than 10%, which belongs to a water layer and is characterized by only water production.

[0004] The eastern fault basin in China has been a high exploration degree area after more than 60 years of exploration, and has entered the stage of exploration of subtle oil and gas reservoirs, and the exploration difficulty is getting greater and greater, while facing investment compression, and it is urgently needed to explore effective methods that can accurately predict the property and oil-bearing property limit of the reservoir production layer to serve the exploration and development investment decision. At present, the prediction technology of oil-bearing property limit is in the literature and patent documents such as the article published by the Geology Science Research Institute of Shengli Oilfield Branch Company of China Petroleum and Chemical Corporation in 2011, the patent application of the Exploration and Development Research Institute of Shengli Oilfield Branch Company of China Petroleum and Chemical Corporation in 2020, and the patent application of China Petroleum University in 2021, which are all aimed at the weight coefficient or correlation analysis of the control of the oil-bearing property of the trap, and give the prediction chart of the oil-bearing trap and the non-oil-bearing trap limit, or give the comprehensive evaluation value of the oil-bearing trap, and then judge whether the trap is oil-bearing or not. The prediction chart of the oil-bearing and non-oil-bearing limit corresponds to the oil-bearing limit of 10% oil saturation, i.e. the oil-bearing limit of water layer and oil-water layer, and does not give the oil-bearing limit of 50% oil saturation, i.e. the oil-bearing limit of pure oil layer and oil-water layer, which cannot comprehensively and effectively predict the oil-bearing limit of the trap in the normal pressure area; in the patent application of the Geology Science Research Institute of Shengli Oilfield Branch Company of China Petroleum and Chemical Corporation in 2014, on the basis of the main reservoir forming dynamics and resistance in the normal pressure environment, a kinetic prediction method for trap reservoir forming in the normal pressure area is established, but the characterization parameters and specific calculation method of the reservoir forming dynamics and resistance are not given, which has certain limitations in the actual application of predicting the oil-bearing limit of the trap in the normal pressure area.

[0005] Therefore, under the condition that the eastern fault basin in China has entered the high exploration degree stage, it is of great significance to increase the evaluation of the oil-bearing limit of the trap in the normal pressure area, carry out the research on the main controlling factors of the oil and gas trap reservoir forming and the change of the oil-bearing property, and establish the targeted technical evaluation method of the oil-bearing limit of the water layer, oil-water layer and pure oil layer trap, which can improve the exploration success rate, reduce the exploration risk and improve the exploration benefit under the current situation of efficient exploration and development. At the same time, the rich oil and gas exploration data in the high exploration degree area also make it possible to predict the oil-bearing limit from the perspective of the main controlling factors of the oil and gas trap reservoir forming. SUMMARY

[0006] The main purpose of the present application is to provide a method for predicting the oil-bearing property limit of traps in normal pressure areas of faulted basins. The method comprises the following steps: determining the spatial distribution range of the normal pressure area of the faulted basin based on the correlation between the oil-bearing saturation of the trap and the oil and gas accumulation elements in the normal pressure area; establishing a limit prediction chart of the oil-bearing property based on the correlation between the oil-bearing saturation of the trap and the accumulation main control elements of different oil-bearing traps such as water layers, oil-water layers and pure oil layers; and predicting the oil-bearing property limit of the trap.

[0007] To achieve the above-mentioned purpose, the present application adopts the following technical solutions:

[0008] The present application provides a method for predicting the oil-bearing property limit of traps in normal pressure areas of faulted basins, which comprises the following steps:

[0009] The formation pressure structure of the faulted basin is determined by using the measured pressure data of the high exploration degree oil and gas basin; and the spatial distribution range of the normal pressure area of the faulted basin is determined.

[0010] The main control factors and quantitative characterization parameters of the trap accumulation and oil-bearing property are determined by the correlation between the characterization parameters of the accumulation elements and the oil-bearing saturation of the normal pressure area reservoir.

[0011] The oil-bearing property of the discovered reservoirs in the normal pressure area of the faulted basin is classified according to the oil-bearing saturation of the trap.

[0012] The correlation between the quantitative characterization parameters of the traps with different oil-bearing saturations in the normal pressure area is used to establish an oil-bearing property limit prediction model.

[0013] The quantitative characterization parameters of the target trap are determined, and the oil-bearing property characteristics of the trap in the normal pressure area are determined by using the oil-bearing property limit prediction model.

[0014] Further, the correlation between the measured formation pressure, pressure coefficient and depth is established by statistical analysis of the measured formation pressure data and pressure coefficient calculation of the high exploration degree oil and gas basin, the pressure structure of the faulted basin is determined, and the distribution depth range of the normal pressure area is preliminarily determined.

[0015] Further, the normal pressure area is a normal pressure distribution area with a pressure coefficient of 0.8-1.2.

[0016] Further, the pressure of the area without measured formation pressure data is predicted by using the equivalent depth method based on the conventional logging acoustic travel time logging data of the well without measured formation pressure in the whole area, the pressure coefficient is calculated, the horizontal and vertical pressure coefficient distribution profiles that can control the whole area are prepared based on the measured formation pressure structure, and the spatial distribution range of the normal pressure area is determined. Further, the pressure of the area without measured formation pressure data is predicted by using the equivalent depth method based on the conventional logging acoustic travel time logging data of the well without measured formation pressure in the whole area, the pressure coefficient is calculated, the horizontal and vertical pressure coefficient distribution profiles that can control the whole area are prepared based on the measured formation pressure structure, and the spatial distribution range of the normal pressure area is determined.

[0017] Further, the pressure coefficient is expressed by the following formula:

[0018] C=(P f -P H ) / P H (Formula 1)

[0019] P H =10 -6 ρgh (Formula 2)

[0020] In the formula, C: pressure coefficient (dimensionless); P f : measured formation pressure (MPa), obtained by pressure test data in the middle of drilling, completion test or oil test; P H : hydrostatic pressure (MPa); ρ: formation water density (kg / m 3 ); g: gravitational acceleration (N / kg); buried depth (m).

[0021] Further, the reservoir-forming elements include oil source, reservoir, trap and migration.

[0022] Further, for the oil source reservoir-forming element, the hydrocarbon source rock hydrocarbon generation intensity is taken as a representation parameter; for the reservoir reservoir-forming element, the porosity is taken as a representation parameter; for the trap reservoir-forming element, the trap amplitude is taken as a representation parameter; and for the migration reservoir-forming element, the permeability of the transport layer, the water head pressure and the upward buoyancy of the continuous oil column in the transport water layer are taken as representation parameters.

[0023] Further, two reservoir-forming element representation parameters with relatively large correlation with the oil saturation of the normal pressure zone reservoir are selected as the quantitative representation parameters.

[0024] Further, the prediction model at least includes a prediction model established between the quantitative representation parameters corresponding to the oil saturation classification critical value when classification is performed.

[0025] Further, the oil-bearing classification of the discovered reservoirs in the normal pressure zone of the fault basin is counted according to the oil saturation division standard: the oil-bearing saturation S0> 50% is an oil layer, 10%≤S0≤50% is an oil-water layer, and S0<10% is a water layer.

[0026] Compared with the prior art, the present application has the following advantages:

[0027] The method of the present application is aimed at the trap reservoir in normal pressure area of a faulted basin. On the basis of determining the distribution range of the normal pressure area, the main controlling factors of reservoir formation are determined by analyzing the correlation between the oil saturation of the trap and the oil-gas accumulation factors in the normal pressure area. The limit prediction chart of oil-bearing property is established based on the correlation between the main controlling factors of reservoir formation in different oil-bearing traps such as water layer, oil-water layer and pure oil layer, so as to realize the prediction of the limit of oil-bearing property of the trap.

[0028] The method of the present application has strong operability and effectively solves the problem of inaccurate or incomplete prediction of the limit of oil-bearing property of the reservoir in the normal pressure area of the faulted basin in the prior art and the problem of being unable to predict before drilling. The method realizes the effect of accurately predicting the limit of oil-bearing property of the trap in the normal pressure area. The method has important theoretical significance and practical application value for accurately predicting the limit of oil-bearing property of the reservoir in the faulted basin and making exploration and development decisions. BRIEF DESCRIPTION OF DRAWINGS

[0029] Figure 1 The flow chart of the method for predicting the limit of oil-bearing property of the trap in the normal pressure area of the faulted basin according to the present application is shown in the figure.

[0030] Figure 2 The pressure system profile of Dongying Sag in a specific embodiment of the present application is shown in the figure.

[0031] Figure 3 The correlation graph between the reservoir formation factors of turbidite trap and the oil-bearing property of the trap in the normal pressure area of Dongying Sag in a specific embodiment of the present application is shown in the figure.

[0032] Figure 4 The limit prediction model of oil-bearing property of turbidite trap in the normal pressure area of Dongying Sag in a specific embodiment of the present application is shown in the figure. DETAILED DESCRIPTION

[0033] It should be noted that the following detailed description is exemplary and is intended to provide further explanation of the present application. Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this application belongs.

[0034] It should be noted that the terms used herein are only for the purpose of describing specific embodiments and are not intended to limit the exemplary embodiments according to the present application. As used herein, the singular form is intended to include the plural form unless the context clearly indicates otherwise, and it should also be understood that when the term "comprise", "include" is used in the specification, it means that there is a feature, step, operation and combination thereof.

[0035] In order to enable those skilled in the art to more clearly understand the technical solutions of the present application, the technical solutions of the present application will be described in detail below with specific embodiments.

[0036] Example 1

[0037] As Figure 1 shown, the trap oil-bearing limit prediction method in the normal pressure area of the rift basin comprises:

[0038] Step 1, using the measured pressure data of the high exploration degree oil and gas basin to determine the formation pressure structure;

[0039] Through the measured formation pressure data statistics and pressure coefficient calculation of the high exploration degree oil and gas basin, the correlation between the measured formation pressure, pressure coefficient and depth is established, the pressure structure of the rift basin is determined, and the distribution depth range of the normal pressure area is preliminarily determined; wherein the high exploration degree rift basin refers to the oil and gas basin with long exploration time, high exploration degree, resource proven rate greater than 50%, and large proportion of reserves found by fine rolling exploration; the normal pressure area is a normal pressure distribution area with a pressure coefficient of 0.8-1.2; the calculation of the pressure coefficient is through the following formula:

[0040] C=(P f -P H ) / P H (Formula 1)

[0041] P H =10 -6 ρgh (Formula 2)

[0042] In the formula, C: pressure coefficient (dimensionless); P f : measured formation pressure (MPa), obtained by pressure test data obtained in drilling test, completion test or oil test; P H : static water pressure (MPa); ρ: formation water density (kg / m 3 ); g: gravity acceleration (N / kg); buried depth (m).

[0043] Step 2, using the mudstone acoustic travel time logging data of the exploration well and the equivalent depth method to determine the formation pressure in the area without measured data, and determining the spatial distribution range of the normal pressure area of the rift basin.

[0044] Through the conventional logging acoustic travel time logging data of the exploration well without measured formation pressure in the whole area, the pressure prediction of the area without measured formation pressure data is carried out by using the equivalent depth method, the pressure coefficient is further calculated by using formula 1 and formula 2, the horizontal and vertical pressure coefficient distribution profile which can control the whole area is prepared on the basis of the measured formation pressure structure, and the spatial distribution range of the normal pressure area is determined. Wherein the exploration well without measured formation pressure refers to the exploration well without drilling test, completion test and oil test, and the measured formation pressure data cannot be obtained due to no pressure test; the equivalent depth method is to judge whether the formation is overpressure by the deviation of the normal compaction trend line of the mudstone and the formation acoustic travel time or velocity, and to estimate the formation pressure according to the deviation degree.

[0045] Step 3, the main controlling factors of trap accumulation and oiliness and their quantitative characterization parameters are determined by the correlation between the characterization parameters of accumulation elements and the oil saturation of the oil reservoirs in the normal pressure zone.

[0046] For the correlation between the oil saturation of the reservoir and the cap rock and preservation conditions, the cap rock conditions and the preservation conditions are not much different in the range of the faulted basin, and have no direct influence on the oiliness difference of different traps. The control of the two factors on the oil saturation can be ignored. For the control of the oil source conditions on the oiliness difference of the traps, the correlation between the oil saturation of the discovered reservoirs and the hydrocarbon generation intensity of the corresponding source rocks is analyzed. The hydrocarbon generation intensity is the hydrocarbon generation capacity per unit area of the source rock, which can be obtained by the following formula:

[0047] E = (10 4 · S · H · p r · C · R p ) / S = 10 4 · H · p r · C · R p (Formula 3)

[0048] In the formula, E is the hydrocarbon generation intensity (t / km 2 ); S is the source rock area (km 2 ); H is the source rock thickness (m); p r is the source rock density (g / cm 3 ); C is the average abundance of source rock layer (percentage of organic carbon content, %); R p is the average oil and gas generated per ton of organic carbon in the history of the earth (kg / t).

[0049] For the control of reservoir conditions on the difference of oiliness of traps, the correlation analysis is made on the oil saturation of discovered reservoirs and the porosity parameters reflecting the physical conditions of the reservoirs, in which the porosity is the percentage of the pore volume in the rock volume, and can be obtained by core sample measurement or logging interpretation; for the control of trap conditions on the difference of oiliness of traps, the correlation analysis is made on the oil saturation of discovered reservoirs and the trap amplitude parameters reflecting the trap conditions, in which the trap amplitude is the vertical distance between the trap high point and the overflow point, and can be obtained by the depth of the trap high point and the depth of the overflow point and calculation; for the control of migration conditions on the difference of oiliness of traps, the correlation analysis is made on the oil saturation of discovered reservoirs and three parameters, i.e. the permeability of the carrier bed reflecting the physical conditions of oil and gas migration, the water head pressure reflecting the dynamic conditions of fluid migration, and the upward buoyancy of the continuous oil column migrating in the carrier water bed, in which the permeability parameter can be obtained by core sample measurement or logging interpretation; for the water-bearing strata below the water table, the water head pressure is equivalent to the water column height that can be supported by the formation pressure, so the formation pressure can be used instead; the upward buoyancy of the continuous oil column migrating in the carrier water bed is calculated according to the following formula:

[0050] P=(ρ 水 -ρ 油 )·g·H 油柱 (Formula 4)

[0051] H 油柱 =P 排 / ρ 油 g (Formula 5)

[0052] In the formula, P: the upward buoyancy of the continuous oil column (Pa); ρ 水 : the density of water (kg / m 3 ); ρ 油 : the density of oil and gas (kg / m 3 ); g: the acceleration of gravity (N / kg); H 油柱 : the height of the continuous oil column (m); P 排 : the displacement pressure of the non-wetting oil phase in the carrier bed (Pa).

[0053] Two reservoir-forming element representation parameters with greater correlation with the oil saturation of the oil reservoirs in the normal pressure zone are selected as the quantitative representation parameters.

[0054] Step 4: The oiliness of the discovered reservoirs in the faulted basin normal pressure zone is classified according to the oil saturation of the traps, i.e. the oil layer with the oil saturation S0> 50%, the oil-water layer with 10%≤S0≤50%, and the water layer with S0<10%.

[0055] Step 5: The quantitative representation parameters of the main controlling factors of the traps in different oil saturation classifications in the faulted basin normal pressure zone are counted.

[0056] Step 6, the correlation between the trapping main controlling factor characterization parameters of different oil saturation classification in the normal pressure area is used to establish the oil-bearing property limit prediction model.

[0057] The relationship chart of the trapping main controlling factor characterization parameters of different traps in the normal pressure area of the faulted basin is compiled, and the data points of the trapping main controlling factor characterization parameters of different oil-bearing property traps have obvious limits. The boundary between the oil layer and the oil-water layer is the prediction limit of the oil saturation of 50%, and the boundary between the oil-water layer and the water layer is the prediction limit of the oil saturation of 10%. Thus, a new prediction model of the oil-bearing property limit of the trap in the normal pressure area of the faulted basin is established. 50 10 Thus, a new prediction model of the oil-bearing property limit of the trap in the normal pressure area of the faulted basin is established.

[0058] Step 7, the trapping main controlling factor characterization parameters of the target trap are determined, and the oil-bearing property characteristics of the trap in the normal pressure area are determined by using the oil-bearing property limit prediction model.

[0059] The trapping main controlling factor characterization parameters of the target trap are determined through the comprehensive analysis of the structure, the deposition and the reservoir or the comparison of the adjacent wells. The intersection point of the data of different trapping main controlling factor characterization parameters is projected onto the oil-bearing property limit prediction model chart. According to the relationship between the intersection point and the oil-bearing property limit regression curves Y 50 and Y 10 , it can be judged that the target trap belongs to the oil layer, the oil-water layer or the water layer, which serves the investment decision-making of exploration and development.

[0060] Example 2

[0061] A prediction method of the oil-bearing property limit of the trap in the normal pressure area of the faulted basin comprises the following steps:

[0062] Step 1: the measured pressure data and the pressure coefficient of the Dongying Sag with the highest exploration degree in the Jiyang Depression are counted, the correlation between the measured formation pressure, the pressure coefficient and the depth is established, the pressure structure of the faulted basin is determined, and the depth distribution range of the normal pressure area is determined as 0-2000m.

[0063] Step 2: the pressure of the area without measured formation pressure data is predicted by the equivalent depth method through the conventional logging acoustic travel time logging data of the well without measured formation pressure in the Dongying Sag, the pressure coefficient is further calculated by using formula 1 and formula 2, the horizontal and vertical pressure coefficient distribution profile which can control the whole area is compiled on the basis of the measured formation pressure structure, and the spatial distribution range of the normal pressure area is determined. Figure 2

[0064] ​​Step 3: The main controlling factors and quantitative characterization parameters of oil and gas accumulation in the normal pressure area are determined by analyzing the correlation between the oil-bearing saturation of the turbidite reservoirs discovered in the normal pressure area and the oil and gas accumulation factors such as source rock, reservoir, cap rock, trap, migration and preservation. The correlation between the oil-bearing saturation of the reservoirs and the cap rock and preservation conditions is controlled by the unified regional tectonic and geological evolution background of the Dongying Sag, and the cap rock conditions and preservation conditions have little difference in the rift basin and have no direct impact on the oil-bearing saturation difference of different traps, so the control of these two factors on the oil-bearing saturation can be ignored. The control of the source rock conditions on the oil-bearing saturation difference of different traps is analyzed by correlating the oil-bearing saturation of the discovered reservoirs with the hydrocarbon generation intensity of the corresponding source rocks. The control of the reservoir conditions on the oil-bearing saturation difference of different traps is analyzed by correlating the oil-bearing saturation of the discovered reservoirs with the porosity parameters reflecting the physical property conditions of the reservoirs. The control of the trap conditions on the oil-bearing saturation difference of different traps is analyzed by correlating the oil-bearing saturation of the discovered reservoirs with the trap amplitude parameters reflecting the trap conditions. The control of the migration conditions on the oil-bearing saturation difference of different traps is analyzed by correlating the oil-bearing saturation of the discovered reservoirs with the permeability of the carrier bed reflecting the physical property conditions of the oil and gas migration, the water head pressure reflecting the fluid migration driving force conditions, and the upward buoyancy of the continuous oil column in the carrier bed reflecting the fluid migration driving force conditions.

[0065] Step 4: The trap amplitude and the reservoir porosity with obvious correlation are determined as the quantitative characterization parameters of the main controlling factors of oil and gas accumulation in the turbidite traps in the normal pressure area of the Dongying Sag by correlating the oil-bearing saturation of the discovered reservoirs with the oil and gas accumulation factors. Figure 3 The greater the trap amplitude and the reservoir porosity, the greater the oil and gas accumulation in the trap, and the higher the oil-bearing saturation of the trap.

[0066] Step 5: The oil-bearing saturation of the discovered reservoirs in the normal pressure area of the rift basin is classified according to the classification standard of the oil-bearing saturation, i.e. the oil-bearing saturation S0> 50% is an oil layer, 10%≤S0≤50% is an oil-water layer, and S0<10% is a water layer. The discovered reservoirs in the normal pressure area are classified into pure oil layers, oil-water layers and water layers according to the classification standard.

[0067] Step 6: The porosity and trap amplitude parameters of the discovered reservoirs with different oil-bearing saturations (pure oil layers, oil-water layers and water layers) in the normal pressure area of the Dongying Sag are respectively counted.

[0068] Step 7: The relationship between the trap amplitude and the porosity of the discovered reservoirs with different oil-bearing saturations (pure oil layers, oil-water layers and water layers) in the normal pressure area of the Dongying Sag is plotted. The intersection points of the porosity and the trap amplitude of different oil-bearing traps have obvious boundaries. The boundary between the oil layers and the oil-water layers is the prediction boundary of the oil-bearing saturation of 50%, and a regression curve Y 50(6), the boundary between the oil-water layer and the water layer is the predicted limit of oil saturation of 10%, and the limit can establish a regression curve Y 10 (7), thus establishing a prediction model of the oil-bearing limit of traps in the normal pressure area of the Dongying Sag.

[0069] Y 50 = 28185x -2.259 ; R 2 = 0.8569 (6)

[0070] Y 10 = 1253.8x -1.466 ; R 2 = 0.868 (7)

[0071] Step 8: The trap amplitude and porosity parameters of the target trap are determined by construction, deposition, reservoir comprehensive analysis, combined with seismic interpretation and adjacent well area comparison, the data intersection point of the porosity and trap amplitude of the target trap is projected onto the oil-bearing limit prediction model chart, and according to the relationship between the intersection point and the oil-bearing limit regression curve Y 50 and Y 10 , it can be judged that the target trap belongs to a pure oil layer, an oil-water layer or a water layer, serving the investment decision-making of exploration and development.

[0072] The above embodiment is a preferred embodiment of the present application, but the embodiment of the present application is not limited by the above embodiment, and any change, modification, substitution, combination, simplification made without departing from the spirit and principle of the present application should be an equivalent replacement mode, and all are included in the protection scope of the present application.

Claims

1. A method for predicting the oil-bearing limit of a trap in a normal pressure area of a rifted basin, characterized in that, The method comprises the following steps: The formation pressure structure of the faulted basin is determined by using the measured pressure data of the high exploration degree oil and gas bearing basin; and the spatial distribution range of the normal pressure zone of the faulted basin is determined; The main controlling factors and the quantitative representation parameters of the trap accumulation and oiliness are determined by the correlation between the representation parameters of the accumulation elements and the oil saturation of the reservoir in the normal pressure zone; The oiliness of the discovered reservoirs in the normal pressure zone of the faulted basin is classified according to the oil saturation of the trap; The oiliness limit prediction model is established by using the correlation between the quantitative representation parameters of the traps with different oil saturations in the normal pressure zone; The quantitative representation parameters of the target trap are determined, and the oiliness characteristics of the trap in the normal pressure zone are determined by using the oiliness limit prediction model.

2. The method according to claim 1, wherein the method is characterized by, The correlation between the measured formation pressure, the pressure coefficient and the depth is established by the statistics of the measured formation pressure data and the calculation of the pressure coefficient of the high exploration degree oil and gas bearing basin, the pressure structure of the faulted basin is determined, and the distribution depth range of the normal pressure zone is preliminarily determined.

3. The method according to claim 1 or 2, wherein the method is characterized by, The normal pressure zone is a normal pressure distribution zone with a pressure coefficient of 0.8-1.

2.

4. The method according to claim 1, wherein the method is characterized by, The pressure of the region without measured formation pressure data is predicted by using the equivalent depth method based on the conventional logging acoustic travel time logging data of the exploration wells without measured formation pressure in the whole region, the pressure coefficient is calculated, the horizontal and vertical pressure coefficient distribution profiles capable of controlling the whole region are prepared based on the measured formation pressure structure, and the spatial distribution range of the normal pressure zone is determined.

5. The method for predicting the oil-bearing limit of a trap in a normal-pressure zone of a rift basin according to claim 4, characterized in that, The pressure coefficient is represented by the following formula: C = (P f -P H ) / P H (Formula 1) P H =10 -6 ρgh (Equation 2) where C: pressure coefficient, dimensionless; P f : measured formation pressure, MPa, obtained from pressure test data acquired during drilling mid-test, completion test, or production test; P H : hydrostatic pressure, MPa; p: formation water density, kg / m 3 ; g: gravitational acceleration, N / kg; h: buried depth, m.

6. The method according to claim 1, wherein the method is characterized by, The accumulation elements include the oil source, the reservoir, the trap and the migration.

7. The method according to claim 1, wherein the method is characterized by, For the oil source accumulation element, the hydrocarbon source rock hydrocarbon generation intensity is used as the representation parameter; for the reservoir accumulation element, the porosity is used as the representation parameter; for the trap accumulation element, the trap amplitude is used as the representation parameter; and for the migration accumulation element, the permeability of the transport layer, the water head pressure and the upward buoyancy of the continuous oil column in the transport water layer are used as the representation parameters.

8. The method according to claim 1, wherein the method is characterized by, Two accumulation element representation parameters with greater correlation with the oil saturation of the reservoir in the normal pressure zone are selected as the quantitative representation parameters.

9. The method according to claim 1, wherein the method is characterized by, The prediction model at least includes the prediction model established between the quantitative representation parameters corresponding to the oil saturation classification critical value when the classification is performed.

10. The method according to claim 1 or 9, wherein the method is characterized by, The oiliness classification of the discovered reservoirs in the normal pressure zone of the faulted basin is counted according to the division standard of the oil saturation: the oil layer is the oil saturation S0>50%, the oil-water layer is 10%≤S0≤50%, and the water layer is S0<10%.

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