CN111007230B

CN111007230B - Method for quantitatively evaluating oil content of low-porosity compact oil reservoir of continental-phase lake basin

Info

Publication number: CN111007230B
Application number: CN201911146054.8A
Authority: CN
Inventors: 白斌; 胡素云; 陶士振; 张天舒
Original assignee: Petrochina Co Ltd
Current assignee: Petrochina Co Ltd
Priority date: 2019-11-21
Filing date: 2019-11-21
Publication date: 2022-03-29
Anticipated expiration: 2039-11-21
Also published as: CN111007230A

Abstract

The invention provides a method for quantitatively evaluating the oil content of a low-porosity compact oil reservoir of a continental lake basin. The method comprises the following steps: determining pore size distribution R of reservoir core to be detected_Original(ii) a By means of R_OriginalDetermining the minimum pore throat diameter, thereby determining the maximum breakthrough pressure and the formation temperature, and determining the fluid content V of the reservoir core to be measured under the temperature and the pressure_{Fluid A}And oil content V_{A oil}The method is used for representing the fluid content and the oil content of all pores of the reservoir core to be detected, including communicated pores and non-communicated pores; by means of R_OriginalDetermining breakthrough pressure and formation temperature corresponding to the median pore throat diameter, and determining fluid content V of the core of the reservoir to be tested at the temperature and the pressure_{B fluid}And oil content V_{B oil}The method is used for representing the fluid content and the oil content of the communicating pore of the reservoir core to be detected; according to V_{Fluid A}、V_{A oil}、V_{B fluid}、V_{B oil}And determining the oil saturation of the connected pores, the oil saturation of the unconnected pores and the total oil saturation to realize quantitative evaluation of the oil content of the compact oil of the continental lake basin.

Description

Method for quantitatively evaluating oil content of low-porosity compact oil reservoir of continental-phase lake basin

Technical Field

The invention relates to an evaluation method for oil content of a compact oil reservoir of a continental lake basin, in particular to a method for quantitatively evaluating the oil content of connected and unconnected pores of the compact oil reservoir.

Background

The continental lake basin develops unconventional oil and gas resources of various reservoir types, and petroleum presents in-situ gathering, adjacent gathering and integrated gathering rules (Zhoucai, etc., unconventional oil and gas geology [ M ], 2011). The reservoir body not only comprises compact sandstone, compact limestone, compact mixed rock and the like, but also comprises a shale reservoir which takes a nano-pore throat as a main component. Crude oil exists in micron-nanometer communicated pores such as inter-granular dissolution pores and microcracks, and is also enriched in intra-granular pores with poor connectivity (white bin, Zhu Ke, Wu Song, and the like.) unconventional oil and gas compact oil reservoir microscopic pore throat structure representation new technology and significance [ J ] China oil exploration, 2014,19(3): 78-86). Particularly, shale oil and low-porosity compact oil resources which are used as a source and storage body are developed through a nanometer pore throat, mostly, unconnected pores are used as main components, and the proportion of the unconnected pores is high (white bin, Zhu Ke, Wu Song Tao and the like. the micro-holing roar structure [ J ] of the compact sandstone is represented by utilizing multi-scale CT imaging, oil exploration and development, 2013,40(3): 329) and 333, the evaluation of oil content of different types of pores determines evaluation standards, development modes and engineering technical methods of continental compact (shale-containing) oil desserts, plays a decisive role in scale exploration and benefit development of continental lake basin compact oil (shale-containing oil), and is one of important parameters for evaluating the quality of unconventional compact oil reservoirs (shale-containing reservoirs).

The method for evaluating the oil and gas content of the compact oil reservoir (shale-containing oil reservoir) of the continental lake basin is more, and two types of methods are mainly used for direct determination and indirect analysis. Most scholars qualitatively or quantitatively detect oil and gas characteristics by using methods such as gas detection, rock pyrolysis, thermal evaporation hydrocarbon chromatography, quantitative fluorescence, rock sample nuclear magnetic resonance, drilling fluid nuclear magnetic resonance, micro fluorescence (fluorescent thin slice), tank top gas light hydrocarbon chromatography, ion chromatography, imaging logging technology and the like on the basis of logging and logging quality. The quantitative fluorescence technology can accurately determine the crude oil property and the oil abundance of a main target stratum by using the characteristics, the maximum peak value, the corresponding wavelength position, the oiliness index and other main parameters of a fluorescence spectrogram. The method is sensitive to the judgment of the crude oil property of the medium-light oil layer, the fluid property of the reservoir and the display of true and false oil and gas. The micro-fluorescence technology is to utilize a fluorescence microscope to simultaneously display stratum rocks and hydrocarbons, so that the types and the abundance of the hydrocarbons (asphaltenes) can be analyzed, and the micro-distribution state of the hydrocarbons can be researched, so that the effectiveness of a storage space can be more effectively analyzed, and the properties of an oil-water layer can be more accurately judged (Zhou Bo. geological logging new technology analysis and application thereof discuss [ J ]. Chinese petroleum and chemical standards and quality, 2018, (9): 135-. The shoji (shoji. contribution of nmr logging to oil and gas resource evaluation [ J ]. proceedings of the institute of petroleum and china, 1998,20(4):39-44) contrasts different imaging logging techniques such as formation microresistivity scanning, peri-well sonography, and nmr logging to evaluate reservoir fluids (anecdotal. application of nmr to nmr in oil logging [ J ]. science and technology, 2015,6: 217).

The nuclear magnetic resonance technology is used for determining parameters such as permeability, saturation and the like of the fluid by measuring the nuclear magnetic resonance intensity of hydrogen nuclei in rock pore fluid and the interaction between the fluid and the rock. The nuclear magnetic resonance has high precision, so the method is widely applied in the exploration and development process of oil and gas fields, and can be used for beam self-security and the like (the beam self-security and low-resistance oil layer identification method is applied to the happy ridge oil field [ J ]. high and new technology enterprises in China, 2010,147(12):55-57) for calculating the water saturation and the oil saturation according to the resistance increasing coefficient of rocks; li Fang et al (Li Fang, Xiaochun, Von Yan Liang, etc.. measurement and correction of oil saturation in NMR logging [ J ] logging engineering, 2009,20(1):11-14) describe in more detail the measurement and correction method of oil saturation in NMR.

In a word, the predecessor relies on logging information, and establishes a plurality of oil-gas-containing evaluation series methods such as fluorescence, nuclear magnetism, gas logging, scanning electron microscope and the like and underground special logging data by using actual samples such as rock cores, rock debris and the like, so that quantitative detection of the oil content of the reservoir is realized. Measurement of oil content, in particular in NMR loggingThe method for measuring the saturation is simple and convenient, needs short time, and solves the problems of long required period and complex process of other methods for measuring the oil saturation at present. When the magnetic resonance technology is used for measuring the oil saturation of a conventional reservoir, the pores are mainly communicated and saturated MnCl₂The measured pore volume and oil content can comprehensively reflect real characteristics by a solution method, but for a low-porosity compact oil reservoir or shale, saturated fluid only richly exists in connected pores, the volume of unconnected pores under different temperatures and pressures is large under the constraint of geological conditions, and the measured oil content saturation has large deviation and cannot meet the accurate evaluation of the oil content of compact (shale) oil.

Disclosure of Invention

Aiming at the defects of the prior art, the invention aims to provide a method for quantitatively evaluating the oil content of a low-porosity compact oil reservoir of a continental lake basin, which is suitable for the low-porosity compact oil reservoir and accurately evaluates the oil content of the reservoir.

In order to achieve the above object, the present invention provides a method for quantitatively evaluating oil content of a reservoir of low-porosity compact oil of a continental lake basin (the compact oil in the present invention refers to compact oil including shale oil, sandstone compact oil, etc.), wherein the method comprises:

1) determining pore size distribution R of reservoir core to be detected_Original；

2) Determining the minimum pore throat diameter by using the pore size distribution obtained in the step 1), determining the maximum breakthrough pressure by using the minimum pore throat diameter, recording the maximum breakthrough pressure as a first pressure, and determining the formation temperature corresponding to the first pressure as a first temperature; determining the fluid content V of the reservoir core to be tested at a first temperature and a first pressure_{Fluid A}And oil content V_{A oil}(fluid content V)_{Fluid A}The method is used for representing the fluid content and the oil content V of the reservoir core to be tested at a first temperature and a first pressure_{A oil}The method is used for representing the oil content of the reservoir core to be detected at a first temperature and a first pressure), and is used for representing the fluid content and the oil content of all pores including communicated pores and non-communicated pores of the reservoir core to be detected;

3) utilizing the steps1) Determining the median pore throat diameter of the obtained pore size distribution, determining breakthrough pressure by using the median pore throat diameter, recording the breakthrough pressure as second pressure, and determining formation temperature corresponding to the second pressure, and recording the formation temperature as second temperature; determining the fluid content V of the reservoir core to be tested at a second temperature and a second pressure_{B fluid}And oil content V_{B oil}(fluid content V)_{B fluid}The method is used for representing the fluid content and the oil content V of the reservoir core to be tested at a second temperature and a second pressure_{B oil}The oil content of the reservoir core to be detected at a second temperature and a second pressure) is represented, and the fluid content and the oil content of a communicating pore of the reservoir core to be detected are represented;

4) the fluid content V determined according to step 2) and step 3)_{Fluid A}Oil content V_{A oil}Fluid content V_{B fluid}Oil content V_{B oil}And determining the oil saturation of the connected pores, the oil saturation of the unconnected pores and the total oil saturation so as to quantitatively evaluate the oil content of the low-porosity compact oil reservoir of the continental lake basin.

In the method for quantitatively evaluating the oil content of the low-porosity compact oil reservoir of the continental lake basin, the oil saturation of the connected pores comprises at least one of the oil saturation of the connected pores with different pore throat sizes and the total oil saturation of all the connected pores; the oil saturation of the non-connected pores comprises at least one of oil saturation of non-connected pores of different pore throat sizes and total oil saturation of all non-connected pores; the total oil saturation includes at least one of oil saturations of pores of different pore throat sizes (including connected pores and disconnected pores) and total oil saturations of all pores (including connected pores and disconnected pores).

In the above method for quantitatively evaluating the oil content of a low-porosity tight oil reservoir of a continental lake basin, the fluid content comprises at least one of the fluid content and the total fluid content of pores with different pore throat sizes; the oil content includes at least one of an oil content and a total oil content of pores of different pore throat sizes. And selecting the fluid content and the oil content to be determined according to the type of the oil content to be evaluated, namely the type of the oil saturation of the connected pores, the oil saturation of the unconnected pores and the total oil saturation. When the oil saturation of the connected pores with different pore throat sizes, the oil saturation of the unconnected pores with different pore throat sizes and the total oil saturation of the pores with different pore throat sizes (including the connected pores and the unconnected pores) need to be determined, the fluid content is the fluid content of the pores with different pore throat sizes, and the oil content is the oil content of the pores with different pore throat sizes; when it is desired to determine the total oil saturation of all connected pores, the total oil saturation of all non-connected pores, the total oil saturation of all pores (including both connected and non-connected pores), the fluid content is the total fluid content and the oil content is the total oil content.

In the method for quantitatively evaluating the oil content of the low-porosity compact oil reservoir of the continental lake basin, the pore size distribution, namely the distribution situation of pore throats with different sizes, can be represented by a pore size-porosity diagram and the porosity distribution corresponding to the pore throats with different sizes.

In the method for quantitatively evaluating the oil content of the low-porosity compact oil reservoir of the continental lake basin, the formation temperature corresponding to the pressure is determined, and then the formation temperature corresponding to the formation depth is determined.

In the method for quantitatively evaluating the oil content of the low-porosity compact oil reservoir of the continental lake basin, preferably, the porosity of the core of the reservoir to be tested is less than 10 percent; more preferably, the porosity of the reservoir core to be tested is determined by adopting a helium gas adsorption method. In the method for quantitatively evaluating the oil content of the low-porosity compact oil reservoir of the continental lake basin, preferably, the pore size distribution R of the core of the reservoir to be tested is determined in the step 1)_OriginalThe method is realized by the following steps: performing nuclear magnetic resonance test on the reservoir core to be tested to obtain a T2 spectrum of the reservoir core to be tested, and obtaining the aperture distribution R of the reservoir core to be tested by using the obtained T2 spectrum_Original。

In the method for quantitatively evaluating the oil content of the low-porosity compact oil reservoir of the continental lake basin, preferably, in the step 2), the fluid content V of the reservoir core to be tested at the first temperature and the first pressure is determined_{Fluid A}And oil content V_{A oil}The method is realized by the following steps: sequentially carrying out saturated water and saturated manganese, namely saturated manganese chloride solution, on the reservoir core to be detected under the conditions of first pressure and first temperature, and respectively carrying out nuclear magnetic resonance test on the reservoir core to be detected after saturated water and saturated manganese to obtain T2 spectrums after saturated water and saturated manganese of the reservoir core to be detected; obtaining the fluid content V of the reservoir core to be detected by using the obtained T2 spectrum of the reservoir core to be detected after being saturated with water_{Fluid A}And obtaining the oil content V of the reservoir core to be detected by using the obtained T2 spectrum of the reservoir core to be detected after being saturated with manganese_{A oil}。

In the method for quantitatively evaluating the oil content of the low-porosity compact oil reservoir of the continental lake basin, preferably, in the step 3), the fluid content V of the reservoir core to be tested at the second temperature and the second pressure is determined_{Fluid A}And oil content V_{A oil}The method is realized by the following steps: sequentially carrying out saturated water and saturated manganese, namely saturated manganese chloride solution, on the reservoir core to be detected under the conditions of second pressure and second temperature, and respectively carrying out nuclear magnetic resonance test on the reservoir core to be detected after saturated water and saturated manganese to obtain T2 spectrums after saturated water and saturated manganese of the reservoir core to be detected; obtaining the fluid content V of the reservoir core to be detected by using the obtained T2 spectrum of the reservoir core to be detected after being saturated with water_{B fluid}And obtaining the oil content V of the reservoir core to be detected by using the obtained T2 spectrum of the reservoir core to be detected after being saturated with manganese_{B oil}。

In the above method for quantitatively evaluating the oil content of the low-porosity tight oil reservoir of the continental lake basin, preferably, the method comprises:

1) determining the porosity of the reservoir core to be detected (preferably determining the porosity of the reservoir core to be detected by adopting a helium gas adsorption method), preparing the reservoir core to be detected with the porosity of less than 10% into A, B samples to be detected, respectively carrying out nuclear magnetic resonance testing on A, B samples to be detected to obtain a T2 spectrum of A, B samples to be detected, and obtaining the pore diameter distribution (namely the pore diameter distribution of the reservoir core to be detected) R of A, B samples to be detected by utilizing the obtained T2 spectrum_Original；

2) Determining the minimum pore throat diameter by using the pore size distribution obtained in the step 1), and determining the maximum pore throat diameter by using the minimum pore throat diameterRecording the breakthrough pressure as a first pressure, and determining a formation temperature corresponding to the first pressure as a first temperature; under the conditions that the pressure is a first pressure and the temperature is a first temperature, sequentially carrying out saturated water and saturated manganese (namely a saturated manganese chloride solution) on a sample to be detected A to simulate the liquid-containing and oil-containing conditions of all pores (including communicated pores and non-communicated pores) of the sample to be detected, and respectively carrying out nuclear magnetic resonance testing on the sample to be detected A after saturated water and saturated manganese to obtain a T2 spectrum of the sample to be detected A after saturated water and saturated manganese; obtaining the fluid content (namely the fluid content of the reservoir core to be detected) V of the sample A to be detected by utilizing the obtained T2 spectrum of the sample A to be detected after the sample A is saturated with water_{Fluid A}And obtaining the oil content (namely the oil content of the reservoir core to be detected) V of the sample A to be detected by utilizing the obtained T2 spectrum of the sample A to be detected after being saturated with manganese_{A oil}；

3) Determining a median pore throat diameter by using the pore size distribution obtained in the step 1), determining breakthrough pressure as a first pressure by using the median pore throat diameter, and determining formation temperature corresponding to the second pressure as a second temperature; under the conditions that the pressure is a second pressure and the temperature is a second temperature, sequentially carrying out saturated water and saturated manganese (namely saturated manganese chloride solution) on the sample to be detected B to respectively simulate the liquid-containing and oil-containing conditions of the communicated pores of the sample to be detected, and respectively carrying out nuclear magnetic resonance testing on the saturated water and the saturated manganese sample to be detected B to obtain a T2 spectrum of the saturated water and the saturated manganese sample to be detected B; obtaining the fluid content (namely the fluid content of the reservoir core to be detected) V of the sample B to be detected by utilizing the obtained T2 spectrum of the sample B to be detected after being saturated with water_{B fluid}And obtaining the oil content (namely the oil content of the reservoir core to be detected) V of the sample B to be detected by utilizing the obtained T2 spectrum of the sample B to be detected after being saturated with manganese_{B oil}；

4) V determined according to step 2), step 3)_{A is saturated with water}、V_{Manganese saturation A}、V_{B saturated water}、V_{B saturated manganese}And determining the oil saturation of the connected pores, the oil saturation of the unconnected pores and the total oil saturation so as to quantitatively evaluate the oil content of the low-porosity compact oil reservoir of the continental lake basin.

In the above method for quantitatively evaluating the oil content of the low-porosity compact oil reservoir of the continental lake basin, preferably,in the process of determining the pore size distribution and/or the fluid content and/or the oil content by using the T2 spectrum, the conversion formula of the relaxation time and the pore throat radius in the T2 spectrum is as follows:

wherein R is pore throat radius, nm; rho₂Surface relaxation rate, nm/ms; t2 is relaxation time, ms; wherein, the conversion formula can be adopted in all or part of the steps 1), 2) and 3)

Pore throat sizing was performed. The surface relaxation rate refers to the influence of the surface of rock particles on the relaxation process; can be determined by conventional means, for example by nuclear magnetic measurements.

In the above method for quantitatively evaluating the oil content of the low-porosity tight oil reservoir of the continental lake basin, preferably, in the step 2), the determination of the maximum breakthrough pressure by using the minimum pore throat diameter is performed by the following method: determining a permeability value corresponding to the pore throat diameter by using the minimum pore throat diameter; then determining the maximum breakthrough pressure by using the permeability value; wherein, the calculation formula for determining the permeability value corresponding to the pore throat diameter by using the minimum pore throat diameter is preferably

Wherein k is the permeability, R is the pore diameter, and phi is the minimum diameter pore throat porosity; the formula for determining the maximum breakthrough pressure using the permeability values is preferably: when the compact oil reservoir is a compact oil sandstone reservoir, the lambda is 0.0956k^-0.875And when the compact oil reservoir is a shale oil reservoir, lambda is-0.319 ln (k) +0.0592, wherein lambda is breakthrough pressure and has a unit of MPa/m, and k is permeability and has a unit of md.

In the above method for quantitatively evaluating the oil content of the low-porosity tight oil reservoir of the continental lake basin, preferably, in the step 3), the determination of the breakthrough pressure by using the median pore throat diameter is performed by the following method: determining a permeability value corresponding to the pore throat diameter by using the median pore throat diameter; then determining the breakthrough pressure by using the permeability value; wherein in the utilizationThe calculation formula for determining the permeability value corresponding to the pore throat diameter is preferably the pore throat diameter

Wherein k is the permeability, R is the pore diameter, and phi is the porosity corresponding to the median pore throat; the formula for determining the breakthrough pressure using the permeability values is preferably: when the compact oil reservoir is a compact oil sandstone reservoir, the lambda is 0.0956k^-0.875And when the compact oil reservoir is a shale oil reservoir, lambda is-0.319 ln (k) +0.0592, wherein lambda is breakthrough pressure and has a unit of MPa/m, and k is permeability and has a unit of md.

In the method for quantitatively evaluating the oil content of the low-porosity compact oil reservoir of the continental lake basin, preferably, the total oil saturation is V_{A oil}÷V_{Fluid A}(ii) a When V is_{A oil}、V_{Fluid A}When the fluid content of the pores with different pore throat sizes is adopted, V corresponding to the pores with different pore throat sizes is respectively adopted_{A oil}Is divided by the corresponding V_{Fluid A}The value of (c).

In the method for quantitatively evaluating the oil content of the low-porosity compact oil reservoir of the continental-facies lake basin, preferably, the oil saturation of the connected pores is equal to V_{B saturated manganese}÷V_{B saturated water}(ii) a When V is_{B oil}、V_{B fluid}When the fluid content of the pores with different pore throat sizes is adopted, V corresponding to the pores with different pore throat sizes is respectively adopted_{B oil}Is divided by the corresponding V_{B fluid}The value of (c).

In the above method for quantitatively evaluating the oil content of the low-porosity compact oil reservoir of the continental lake basin, preferably, the unconnected pore oil saturation ═ V_{A oil}-V_{B oil})÷(V_{Fluid A}-V_{B fluid}). When V is_{Manganese saturation A}、V_{A is saturated with water}、V_{B saturated manganese}、V_{B saturated water}Determining V corresponding to each pore of different pore throat size when the fluid content of the pore of different pore throat size_{A oil}、V_{Fluid A}、V_{B oil}、V_{B fluid}The value of (A) is represented by the formula (V)_{A oil}-V_{B oil})÷(V_{Fluid A}-V_{B fluid}) Respectively calculating the croup sizes of different holesOil saturation of the interconnected pores.

In the above method for quantitatively evaluating the oil content of the low-porosity tight oil reservoir of the continental lake basin, preferably, the method further comprises: determining the pore size distribution of the reservoir core to be detected at a first temperature and a first pressure; in a specific embodiment, under the conditions that the pressure is a first pressure and the temperature is a first temperature, saturated water and saturated manganese (namely saturated manganese chloride solution) are sequentially performed on a reservoir core to be tested, and nuclear magnetic resonance tests are respectively performed on the reservoir core to be tested after the saturated water and the saturated manganese are performed, so that a T2 spectrum of the reservoir core to be tested after the saturated water and the saturated manganese are obtained; obtaining the aperture distribution R of the reservoir core to be measured by using the obtained T2 spectrum of the reservoir core to be measured after being saturated with water_{A is saturated with water}And obtaining the aperture distribution R of the reservoir core to be detected by using the obtained T2 spectrum of the reservoir core to be detected after being saturated with manganese_{Manganese saturation A}。

In the above method for quantitatively evaluating the oil content of the low-porosity tight oil reservoir of the continental lake basin, preferably, the method further comprises: determining the pore size distribution of the reservoir core to be detected at a second temperature and a second pressure; in a specific embodiment, under the conditions that the pressure is a second pressure and the temperature is a second temperature, saturated water and saturated manganese (namely saturated manganese chloride solution) are sequentially performed on the reservoir core to be tested, and nuclear magnetic resonance tests are respectively performed on the reservoir core to be tested after the saturated water and the saturated manganese are performed, so that a T2 spectrum of the reservoir core to be tested after the saturated water and the saturated manganese are obtained; obtaining the aperture distribution R of the reservoir core to be measured by using the obtained T2 spectrum of the reservoir core to be measured after being saturated with water_{B saturated water}And obtaining the aperture distribution R of the reservoir core to be detected by using the obtained T2 spectrum of the reservoir core to be detected after being saturated with manganese_{B saturated manganese}。

In the method for quantitatively evaluating the oil content of the low-porosity compact oil reservoir of the continental lake basin, the determination of the fluid content and the oil content by the T2 spectrum can be carried out by adopting a conventional method in the field; this can be determined, for example, by the following equation:

the fluid content and the oil content are equal to

Wherein t isT corresponding to different saturated fluids₂A relaxation time value, T1 is a lower limit of the T2 relaxation time value corresponding to the pore size of the pore in which the fluid to be investigated is located, T2 is an upper limit of the T2 relaxation time value corresponding to the pore size of the pore in which the fluid to be investigated is located, A (T) is T₂Spectrogram curve T₂Signal strength and T₂Relaxation time dependence.

The method for quantitatively evaluating the oil content of the low-porosity compact oil reservoir of the continental lake basin calculates the corresponding breakthrough pressure based on the pore diameter of the low-porosity sample, obtains the temperature-pressure environment simulation parameter under the geological condition, determines the fluid content and the oil content of the compact oil reservoir based on the geological condition (in a preferred embodiment, obtains the saturated fluid nuclear magnetic resonance data of the compact oil reservoir (shale) based on the geological condition, determines the fluid content and the oil content of the compact oil reservoir (shale) based on the geological condition by utilizing data such as a saturated water signal, a saturated manganese chloride fluid signal and the like), quantitatively calculates the oil content of connected pores and unconnected pores in the micro pores of the compact oil reservoir, realizes the accurate evaluation of the oil content in the micro pores of the compact oil reservoir, and is the evaluation standard of continental compact oil desserts, the development mode and the engineering technical method provide a basis.

The invention provides a technical method for realizing accurate and quantitative evaluation of oiliness of unconnected pores and connected pores of a continental facies compact oil reservoir, aiming at a low-porosity compact oil reservoir and developing quantitative evaluation of oiliness under the constraint of a simulated temperature-pressure geological process based on real geological conditions. Compared with the prior art, the technical scheme provided by the invention has the following advantages:

1. the technical scheme provided by the invention not only considers the evaluation of the oiliness of the connected pores of the compact oil reservoir, but also considers the calculation and evaluation of the unconnected pores, and the mutual verification and the mutual complementation are perfect, so that the comprehensive evaluation of the oiliness of the compact oil reservoir with low porosity is realized, and the goals of completeness, accuracy, quantitative prediction and objective evaluation are realized.

2. The technical scheme provided by the invention is more suitable for evaluating the oil content of the low-porosity compact oil reservoir; the porosity of the compact oil reservoir is distributed by about 1-15%, wherein the compact oil reservoir with the porosity of more than 8% is communicated with pores and develops, the volume of unconnected pores is small, the evaluation on the oil content is small, but the compact sandstone and shale with the porosity of less than 5% have poor pore connectivity, the volume of unconnected pores is large, the permeability is low, and the accurate evaluation on the oil content is influenced. In particular shale oil is commonly distributed in unconnected pores.

3. The technical scheme provided by the application is based on the temperature and pressure environment of geological conditions, the oil content of the in-situ temperature and pressure condition is tested, the oil content of the compact oil reservoir is accurately evaluated, and the influence of the temperature and pressure environment under different geological conditions on the oil content of the compact oil reservoir is avoided.

Drawings

FIG. 1 is a flow chart of a method for quantitatively evaluating the oil content of unconnected pores of a compact oil reservoir of a continental lake basin.

Fig. 2A is a T2 spectrum of the sample to be tested in example 1 a.

Fig. 2B is a T2 spectrum of the sample to be tested in example 1 a.

FIG. 3A is a graph showing the pore size distribution R of the sample to be measured in example 1A_aPrime、R_{A is saturated with water}、R_{Manganese saturation A}Figure (a).

FIG. 3B is a diagram illustrating the aperture distribution R of the sample to be measured in example 1B_Boriginal、R_{B saturated water}、R_{B saturated manganese}Figure (a).

Fig. 4A is a T2 spectrum of the sample to be tested in example 2 a.

Fig. 4B is a T2 spectrum of the sample to be tested B in example 2.

FIG. 5A is the pore size distribution R of the sample to be detected in example 2A_aPrime、R_{A is saturated with water}、R_{Manganese saturation A}Figure (a).

FIG. 5B is the pore size distribution R of the sample to be detected in B of example 2_Boriginal、R_{B saturated water}、R_{B saturated manganese}Figure (a).

Detailed Description

The technical solutions of the present invention will be described in detail below in order to clearly understand the technical features, objects, and advantages of the present invention, but the present invention is not limited to the practical scope of the present invention.

Example 1

The embodiment provides a method for quantitatively evaluating the oil content of a continental lake basin low-porosity shale oil reservoir, wherein the method comprises the following steps:

1) determining the porosity of a reservoir core to be tested (the lithology is a shale sample with the Ordos basin length of 7) by a helium gas adsorption method, directly testing the oil content of the reservoir by the reservoir core to be tested with the porosity of more than 10%, and measuring the oil content of the reservoir core to be tested with the porosity of less than or equal to 10% by a subsequent method; preparing A, B samples to be detected from the reservoir core to be detected, wherein the porosity test result of the reservoir core A, B to be detected is shown in table 1;

TABLE 1

Lithology	Gas porosity (%)
		Shale	2.054(A)、1.652(B)

2) Respectively performing Nuclear Magnetic Resonance (NMR) tests on A, B samples to be detected to obtain A, B T2 spectra of the samples to be detected (shown in FIGS. 2A and 2B, respectively, in FIGS. 2A and 2B, the original sample is the T2 spectrum obtained in the step), and obtaining the pore diameter distribution R of the compact oil reservoir with different porosities by using the obtained T2 spectrum_Original(ii) a Wherein, the conversion formula of the T2 spectrum and the pore throat radius is as follows:

r is the pore throat radius, ρ₂For surface relaxation rate, T2 is the relaxation time; pore size distribution R of sample A, B to be tested_aPrime、R_BoriginalThe results are shown in FIGS. 3A and 3B;

3) determination of pore size distribution by means of step 2)Minimum pore throat diameter (0.001 um as a result); determining the permeability value corresponding to the pore throat diameter by using the minimum pore throat diameter, wherein the specific calculation formula is

Wherein k is the permeability (mD), R is the pore diameter (um), and phi is the porosity; then, determining the maximum breakthrough pressure by using the permeability value (the result is shown in table 2), wherein the specific calculation formula is as follows; λ ═ 0.319ln (k) +0.0592, where λ is the breakthrough pressure in MPa, k is the permeability in md; determining the corresponding formation temperature according to the determined maximum breakthrough pressure and recording the formation temperature as a first temperature (99 ℃); sequentially carrying out saturated water and saturated manganese (namely saturated manganese chloride solution) on the sample to be detected A under the conditions that the pressure is the maximum breakthrough pressure value and the temperature is the first temperature, and respectively carrying out nuclear magnetic resonance testing on the saturated water and the sample to be detected A after saturated manganese to obtain a T2 spectrum (shown in figure 2A, wherein the saturated water sample is a T2 spectrum after the saturated water of the sample to be detected A, and the saturated manganese sample is a T2 spectrum after the saturated manganese of the sample to be detected A); obtaining the aperture distribution R of the sample A to be detected by utilizing the obtained T2 spectrum of the sample A to be detected after being saturated with water_{A is saturated with water}(as shown in FIG. 3A), and a sample V to be measured_{A is saturated with water}Obtaining the aperture distribution R of the sample A to be detected by utilizing the obtained T2 spectrum of the sample A to be detected after being saturated with manganese_{Manganese saturation A}(as shown in FIG. 3A), and a sample V to be measured_{Manganese saturation A}；

Wherein the content of the first and second substances,

wherein T1 is a lower limit of a T2 relaxation time value corresponding to the pore size of the pore in which the fluid to be studied is located, i.e., a lower limit of a T2 relaxation time of the saturated water sample curve in fig. 2A, T2 is an upper limit of a T2 relaxation time value corresponding to the pore size of the pore in which the fluid to be studied is located, i.e., an upper limit of a T2 relaxation time of the saturated water sample curve in fig. 2A, and a (T) is a corresponding T2 spectrum curve, i.e., the saturated water sample curve in fig. 2A;

wherein the content of the first and second substances,

where t1 is the flow to be investigatedA lower limit of a T2 relaxation time value corresponding to the aperture size of the aperture in which the body is located, i.e., a lower limit of a T2 relaxation time of the saturated manganese-like curve in fig. 2A, T2 is an upper limit of a T2 relaxation time value corresponding to the aperture size of the aperture in which the fluid to be studied is located, i.e., an upper limit of a T2 relaxation time of the saturated manganese-like curve in fig. 2A, a (T) is a corresponding T2 spectrum curve, i.e., the saturated manganese-like curve in fig. 2A;

TABLE 2 maximum breakthrough pressure for the samples

Lithology	Maximum breakthrough pressure/MPa
		Shale	2.69

4) Determining the median pore throat diameter (the result is 0.016813um) by utilizing the pore size distribution obtained in the step 1); determining the permeability value corresponding to the pore throat diameter by utilizing the median pore throat diameter, wherein the specific calculation formula is

Wherein k is permeability, R is pore diameter, and phi is porosity; then determining the breakthrough pressure by using the permeability value and recording the breakthrough pressure as a second pressure (the result is 1.58MPa), wherein the specific calculation formula is as follows; λ ═ 0.319ln (k) +0.0592, where λ is the breakthrough pressure in MPa, k is the permeability in md; determining a corresponding formation temperature according to the determined second pressure and recording the formation temperature as a second temperature (86 ℃); sequentially carrying out saturated water and saturated manganese (namely saturated manganese chloride solution) on the sample to be detected B under the conditions of second pressure and second temperature, and respectively carrying out Nuclear Magnetic Resonance (NMR) test on the sample to be detected B after saturated water and saturated manganese to obtain T2 spectrums of the sample to be detected B after saturated water and saturated manganese (the result is shown in figure 2B, wherein the type of the pore is B sample to be detectedThe T2 spectrum after water saturation and the oil signal are the T2 spectrum of the sample B to be detected after manganese saturation), and the obtained T2 spectrum of the sample B to be detected after water saturation is utilized to obtain the aperture distribution R of the sample B to be detected_{B saturated water}(as shown in FIG. 3B) and V_{B saturated water}Obtaining the aperture distribution R of the sample B to be detected by utilizing the obtained T2 spectrum of the sample B to be detected after being saturated with manganese_{B saturated manganese}(as shown in FIG. 3B) and V_{B saturated manganese}；

Wherein the content of the first and second substances,

wherein T1 is a lower limit of a T2 relaxation time value corresponding to the pore size of the pore in which the fluid to be studied is located, i.e., a lower limit of a T2 relaxation time of the saturated water sample curve in fig. 2B, T2 is an upper limit of a T2 relaxation time value corresponding to the pore size of the pore in which the fluid to be studied is located, i.e., an upper limit of a T2 relaxation time of the saturated water sample curve in fig. 2B, a (T) is a corresponding T2 spectrum curve, i.e., the saturated water sample curve in fig. 2B;

wherein the content of the first and second substances,

wherein T1 is a lower limit of a T2 relaxation time value corresponding to the pore size of the fluid to be studied, i.e., a lower limit of a T2 relaxation time of the saturated manganese-like curve in fig. 2B, T2 is an upper limit of a T2 relaxation time value corresponding to the pore size of the fluid to be studied, i.e., an upper limit of a T2 relaxation time of the saturated manganese-like curve in fig. 2B, a (T) is a corresponding T2 spectrum curve, i.e., the saturated manganese-like curve in fig. 2B;

5) v determined according to step 3), step 4)_{A is saturated with water}、V_{Manganese saturation A}、V_{B saturated water}、V_{B saturated manganese}Determining the oil saturation of the connected pores, the oil saturation of the unconnected pores and the total oil saturation, wherein the total oil saturation is V_{Manganese saturation A}÷V_{A is saturated with water}The oil saturation of the interconnected pores is V_{B saturated manganese}÷V_{B saturated water}The unconnected pore has an oil saturation of (V)_{Manganese saturation A}-V_{B saturated manganese})÷(V_{A is saturated with water}-V_{B saturated water}) Therefore, quantitative evaluation of the oil content of the low-porosity compact oil reservoir of the continental lake basin is realized (the result is shown in Table 3).

Table 3 porosity characteristics of test samples

Example 2

The embodiment provides a method for quantitatively evaluating the oil content of a low-porosity tight oil sandstone reservoir of a continental lake basin, wherein the method comprises the following steps:

1) determining the porosity of a reservoir core to be tested (the lithology is a sandstone sample with the Ordos basin length of 7) by a helium gas adsorption method, directly testing the oil content of the reservoir by using the reservoir core to be tested with the porosity of more than 10%, and measuring the oil content of the reservoir core to be tested with the porosity of less than or equal to 10% by using a subsequent method; preparing A, B samples to be detected from the reservoir core to be detected, wherein the porosity test result of the reservoir core A, B to be detected is shown in table 4;

TABLE 4

Lithology	Gas porosity (%)
		Sandstone	8.665(A)、8.945(B)

2) Preparing a reservoir core to be detected with porosity of less than 10% into A, B samples to be detected, respectively performing nuclear magnetic resonance testing on A, B samples to be detected to obtain a T2 spectrum of A, B samples to be detected (as shown in fig. 4A and 4B, the original sample is the T2 spectrum obtained in the step), and obtaining the pore diameter distribution R of the compact oil reservoir with different porosities by using the obtained T2 spectrum_Original(ii) a Wherein, the conversion formula of the T2 spectrum and the pore size distribution is as follows:

r is the throat radius, i.e. the pore diameter, p₂For surface relaxation rate, T2 is the relaxation time; pore size distribution R of sample A, B to be tested_OriginalThe results are shown in FIG. 5A and FIG. 5B (in FIG. 5A, the original aperture distribution R of the sample A to be measured is shown_OriginalIn FIG. 5B, the original aperture distribution R of the sample B to be measured_Original)；

3) Determining the minimum pore throat diameter (the result is 0.005um) by using the pore size distribution obtained in the step 2); determining the permeability value corresponding to the pore throat diameter by using the minimum pore throat diameter, wherein the specific calculation formula is

Wherein k is permeability, R is pore diameter, and phi is porosity; then, determining the maximum breakthrough pressure by using the permeability value (the result is shown in table 5), wherein the specific calculation formula is as follows; λ 0.0956k^-0.875Wherein, lambda is breakthrough pressure, unit is MPa/m, k is permeability, unit is md; determining a corresponding formation temperature (120 ℃) according to the determined maximum breakthrough pressure and recording as a first temperature; sequentially carrying out saturated water and saturated manganese (namely saturated manganese chloride solution) on the sample A to be detected under the conditions that the pressure is the maximum breakthrough pressure value and the temperature is the first temperature, respectively carrying out nuclear magnetic resonance testing on the saturated water and the sample A to be detected after saturated manganese to obtain a saturated water and a T2 spectrum of the sample A to be detected after saturated manganese (as shown in figure 4A, the saturated water sample is a T2 spectrum after the saturated water of the sample A to be detected, and the saturated manganese sample is a T2 spectrum after the saturated manganese of the sample A to be detected), and obtaining the aperture distribution R of the sample A to be detected by using the obtained T2 spectrum of the sample A to be detected after the saturated water_{A is saturated with water}(as shown in FIG. 5A) and a sample V to be measured_{A is saturated with water}Obtaining the aperture distribution R of the sample A to be detected by utilizing the obtained T2 spectrum of the sample A to be detected after being saturated with manganese_{Manganese saturation A}(as shown in FIG. 5A) and a sample V to be measured_{Manganese saturation A}(ii) a (see figure 1 for a specific flow chart) in which,

wherein T1 is the lower limit of the T2 relaxation time value corresponding to the pore size of the pore in which the fluid to be studied is located, i.e. the T2 relaxation time of the saturated water curve in FIG. 4AThe lower limit, T2, is the upper limit of the T2 relaxation time value corresponding to the pore size of the pore in which the fluid to be studied is located, i.e., the upper limit of the T2 relaxation time of the saturated water curve in fig. 4A, a (T) is the corresponding T2 spectrum curve, i.e., the saturated water curve in fig. 4A;

wherein the content of the first and second substances,

wherein T1 is a lower limit of a T2 relaxation time value corresponding to the pore size of the fluid to be studied, i.e., a lower limit of a T2 relaxation time of the saturated manganese-like curve in fig. 4A, T2 is an upper limit of a T2 relaxation time value corresponding to the pore size of the fluid to be studied, i.e., an upper limit of a T2 relaxation time of the saturated manganese-like curve in fig. 4A, and a (T) is a corresponding T2 spectrum curve, i.e., the saturated manganese-like curve in fig. 4A;

TABLE 5

Lithology	Maximum breakthrough pressure/MPa
		Sandstone	2.57

4) Determining the median pore throat diameter (the result is 0.18022um) by utilizing the pore size distribution obtained in the step 1); determining the permeability value corresponding to the pore throat diameter by utilizing the median pore throat diameter, wherein the specific calculation formula is

Wherein k is permeability, R is pore diameter, and phi is porosity; then determining the breakthrough pressure by using the permeability value and recording the breakthrough pressure as a second pressure (the result is 1.95MPa), wherein the specific calculation formula is as follows; λ 0.0956k^-0.875Wherein, lambda is breakthrough pressure, unit is MPa/m, k is permeability, unit is md; according to the factDetermining a corresponding formation temperature as a second temperature (95 ℃) according to the determined second pressure; sequentially carrying out saturated water and saturated manganese (namely saturated manganese chloride solution) on the sample to be detected B under the conditions that the pressure is a second pressure value and the temperature is a second temperature, respectively carrying out nuclear magnetic resonance testing on the saturated water and the sample to be detected B after saturated manganese to obtain a saturated water and a T2 spectrum of the sample to be detected B (as shown in figure 4B, the saturated water sample is a T2 spectrum after the saturated water of the sample to be detected B, and the saturated manganese sample is a T2 spectrum after the saturated manganese of the sample to be detected B), and obtaining the aperture distribution R of the sample to be detected B by using the obtained T2 spectrum of the sample to be detected B after the saturated water_{B saturated water}(as shown in FIG. 5B) and V_{B saturated water}Obtaining the aperture distribution R of the sample B to be detected by utilizing the obtained T2 spectrum of the sample B to be detected after being saturated with manganese_{B saturated manganese}(as shown in FIG. 5B) and V_{B saturated manganese}；

Wherein the content of the first and second substances,

wherein T1 is a lower limit of a T2 relaxation time value corresponding to the pore size of the pore in which the fluid to be studied is located, i.e., a lower limit of a T2 relaxation time of the saturated water sample curve in fig. 4B, T2 is an upper limit of a T2 relaxation time value corresponding to the pore size of the pore in which the fluid to be studied is located, i.e., an upper limit of a T2 relaxation time of the saturated water sample curve in fig. 4B, a (T) is a corresponding T2 spectrum curve, i.e., the saturated water sample curve in fig. 4B;

wherein the content of the first and second substances,

wherein T1 is a lower limit of a T2 relaxation time value corresponding to the pore size of the fluid to be studied, i.e., a lower limit of a T2 relaxation time of the saturated manganese-like curve in fig. 4B, T2 is an upper limit of a T2 relaxation time value corresponding to the pore size of the fluid to be studied, i.e., an upper limit of a T2 relaxation time of the saturated manganese-like curve in fig. 4B, a (T) is a corresponding T2 spectrum curve, i.e., the saturated manganese-like curve in fig. 4B;

5) v determined according to step 3), step 4)_{A is saturated with water}、V_{Manganese saturation A}、V_{B saturated water}、V_{B saturated manganese}Determining the oil saturation of the connected pores, the oil saturation of the unconnected pores and the total oil saturation, wherein the total oil saturation is V_{Manganese saturation A}÷V_{A is saturated with water}The oil saturation of the connected pores is V_{B saturated manganese}÷V_{B saturated water}The unconnected pore has an oil saturation of (V)_{Manganese saturation A}-V_{B saturated manganese})÷(V_{A is saturated with water}-V_{B saturated water}) Therefore, quantitative evaluation of the oil content of the low-porosity compact oil reservoir of the continental lake basin is realized (the result is shown in Table 6).

TABLE 6 porosity characteristics of test samples

Finally, the description is as follows: although the present invention has been described in detail with reference to the above embodiments, it should be understood by those skilled in the art that: modifications and equivalents may be made thereto without departing from the spirit and scope of the invention and it is intended to cover any modifications or equivalents as may fall within the scope of the invention.

Claims

1. A method for quantitatively evaluating the oil content of a low-porosity compact oil reservoir of a continental lake basin, wherein the method comprises the following steps:

2) Determining the minimum pore throat diameter by utilizing the pore size distribution obtained in the step 1), determining the maximum breakthrough pressure by utilizing the minimum pore throat diameter and recording the maximum breakthrough pressure as a first pressure, and determining the formation temperature corresponding to the first pressure and recording the formation temperature as a first temperature; determining the fluid content V of the reservoir core to be tested at a first temperature and a first pressure_{Fluid A}And oil content V_{A oil}The method is used for representing the fluid content and the oil content of all pores including communicated pores and non-communicated pores of the reservoir core to be detected;

3) determining a median pore throat diameter by using the pore size distribution obtained in the step 1), determining breakthrough pressure by using the median pore throat diameter and recording the breakthrough pressure as a second pressure, determining a formation temperature corresponding to the second pressure and recording the formation temperature as a second temperature; determining reservoir to be testedFluid content V of the layer core at a second temperature and a second pressure_{B fluid}And oil content V_{B oil}The method is used for representing the fluid content and the oil content of the communicating pore of the reservoir core to be detected;

2. The method of claim 1, wherein the porosity of the reservoir core under test is less than 10%.

3. The method as claimed in claim 2, wherein the porosity of the reservoir core to be tested is determined using a helium gas adsorption method.

4. The method as claimed in claim 1, wherein the pore size distribution R of the reservoir core to be tested is determined in step 1)_OriginalThe method is realized by the following steps: performing nuclear magnetic resonance test on the reservoir core to be tested to obtain a T2 spectrum of the reservoir core to be tested, and obtaining the aperture distribution R of the reservoir core to be tested by using the obtained T2 spectrum_Original。

5. The method as claimed in claim 1, wherein in step 2), the fluid content V of the reservoir core to be tested at a first temperature and a first pressure is determined_{Fluid A}And oil content V_{A oil}The method is realized by the following steps:

sequentially performing saturated water treatment and saturated manganese treatment on the reservoir core to be detected under the conditions of first pressure and first temperature, and performing nuclear magnetic resonance test on the reservoir core to be detected after the saturated water treatment and the saturated manganese treatment respectively to obtain a T2 spectrum after the saturated water treatment and the saturated manganese treatment of the reservoir core to be detected; obtaining the fluid content V of the reservoir core to be detected by using the obtained T2 spectrum of the reservoir core to be detected after saturated water treatment_{Fluid A}By usingObtaining the oil content V of the reservoir core to be detected by the T2 spectrum after the reservoir core to be detected is treated with saturated manganese_{A oil}。

6. The method as claimed in claim 1, wherein in step 3), the fluid content V of the reservoir core to be tested at the second temperature and the second pressure is determined_{B fluid}And oil content V_{B oil}The method is realized by the following steps:

sequentially performing saturated water treatment and saturated manganese treatment on the reservoir core to be detected under the conditions of second pressure and second temperature, and performing nuclear magnetic resonance test on the reservoir core to be detected after the saturated water treatment and the saturated manganese treatment respectively to obtain a T2 spectrum after the saturated water treatment and the saturated manganese treatment of the reservoir core to be detected; obtaining the fluid content V of the reservoir core to be detected by using the obtained T2 spectrum of the reservoir core to be detected after saturated water treatment_{B fluid}And obtaining the oil content V of the reservoir core to be detected by using the obtained T2 spectrum of the reservoir core to be detected after saturated manganese treatment_{B oil}。

7. The method of claim 1, wherein the method comprises:

1) determining the porosity of the reservoir core to be detected, preparing the reservoir core to be detected with the porosity less than 10% into A, B samples to be detected, respectively carrying out nuclear magnetic resonance testing on A, B samples to be detected to obtain a T2 spectrum of A, B samples to be detected, and obtaining the aperture distribution R of the samples to be detected by utilizing the obtained T2 spectrum_Original；

2) Determining the minimum pore throat diameter by using the pore size distribution obtained in the step 1), determining the maximum breakthrough pressure by using the minimum pore throat diameter, recording the maximum breakthrough pressure as a first pressure, and determining the formation temperature corresponding to the first pressure as a first temperature; sequentially carrying out saturated water treatment and saturated manganese treatment on the sample to be detected A under the conditions of first pressure and first temperature to obtain a saturated water treatment and saturated manganese treatment T2 spectrum of the sample to be detected A; obtaining the fluid content V of the sample A to be detected by utilizing the obtained T2 spectrum of the sample A to be detected after saturated water treatment_{Fluid A}Using the obtainedObtaining the oil content V of the sample A to be detected by the T2 spectrum of the sample A to be detected after the saturated manganese treatment_{A oil}；

3) Determining a median pore throat diameter by using the pore size distribution obtained in the step 1), determining breakthrough pressure by using the median pore throat diameter, recording the breakthrough pressure as a second pressure, and determining formation temperature corresponding to the second pressure, and recording the formation temperature as a second temperature; under the conditions of a second pressure and a second temperature, sequentially carrying out saturated water treatment and saturated manganese treatment on the sample to be detected B, namely a saturated manganese chloride solution, and respectively carrying out nuclear magnetic resonance testing on the sample to be detected B after the saturated water treatment and the saturated manganese treatment to obtain a T2 spectrum of the sample to be detected B after the saturated water treatment and the saturated manganese treatment; obtaining the fluid content V of the sample B to be detected by using the obtained T2 spectrum of the sample B to be detected after saturated water treatment_{B fluid}And obtaining the oil content V of the sample B to be detected by using the T2 spectrum of the sample B to be detected after the saturated manganese treatment_{B oil}；

8. The method as claimed in claim 7, wherein determining the porosity of the reservoir core to be tested is performed using a helium gas adsorption method.

9. The method according to any one of claims 4-8, wherein in determining pore size distribution and/or fluid content and/or oil content using the T2 spectrum, the conversion of relaxation time to pore throat radius in the T2 spectrum is:

wherein R is pore throat radius, nm; rho₂Surface relaxation rate, nm/ms; t2 is the relaxation time, ms.

10. The method according to claim 1 or 7, wherein in step 2) the determining the maximum breakthrough pressure using the minimum pore throat diameter is performed by: determining a permeability value corresponding to the pore throat diameter by using the minimum pore throat diameter; the permeability value is then used to determine the maximum breakthrough pressure.

11. The method of claim 10, wherein the permeability value corresponding to the minimum throat diameter is determined using the calculation formula for the minimum throat diameter as

Wherein k is permeability, md; r is the pore throat diameter, mu m; phi is the porosity corresponding to the minimum diameter pore throat.

12. The method of claim 10, wherein the maximum breakthrough pressure is determined using the permeability value as calculated by the formula: when the compact oil reservoir is a compact sandstone reservoir, the lambda is 0.0956k^-0.875(ii) a λ ═ 0.319ln (k) +0.0592 when the tight oil reservoir is a shale oil reservoir; wherein, lambda is breakthrough pressure and the unit is MPa/m, k is permeability and the unit is md.

13. The method according to claim 1 or 6, wherein in step 3), the determination of breakthrough pressure using median pore throat diameter is performed by: determining a permeability value corresponding to the pore throat diameter by using the median pore throat diameter; the permeability value is then used to determine the breakthrough pressure.

14. The method of claim 12, wherein the median pore throat diameter is used to determine a permeability value for the pore throat diameter by the calculation of

Wherein k is permeability, md; r is the pore throat diameter, mu m; phi is the porosity corresponding to the median pore throat.

15. The method of claim 12, wherein utilizingThe calculation formula for determining the breakthrough pressure by the permeability value is as follows: when the compact oil reservoir is a compact oil sandstone reservoir, the lambda is 0.0956k^-0.875(ii) a λ ═ 0.319ln (k) +0.0592 when the tight oil reservoir is a shale oil reservoir; wherein, lambda is breakthrough pressure and the unit is MPa/m, k is permeability and the unit is md.

16. The method of claim 1 or 7,

total oil saturation ═ V_{A oil}÷V_{Fluid A}；

Oil saturation of interconnected pores (V)_{B oil}÷V_{B fluid}；

The oil saturation of the unconnected pores is (V)_{A oil}-V_{B oil})÷(V_{Fluid A}-V_{B fluid})。