Evaluation method for hydrogen-bearing components, porosity and pore size distribution of organic-rich shale

Abstract

An evaluation method for hydrogen-bearing components, porosity and pore size distribution of organic-rich shale is provided, relating to a technical field of oil and gas development. The evaluation method includes steps of: according to differences among NMR (nuclear magnetic resonance) T.sub.1-T.sub.2 maps of kerogen, oil-adsorbed kerogen, clay minerals of different water-containing conditions, shale, dry shale sample, oil-saturated shale sample and water-saturated shale sample, establishing a classification scheme for each hydrogen-bearing component and a quantitative characterization method for fluid components of the organic-rich shale; with a T.sub.2 distribution of the organic-rich shale after being saturated with oil as a target and a T.sub.2 distribution of the dry shale sample as a basement, subtracting the basement, and obtaining a T.sub.2 distribution of oil in pores; and based on the T.sub.2 distribution of oil in the pores, evaluating the porosity and the pore size distribution of the organic-rich shale. Compared with a conventional method, the present invention shows relatively high innovativeness and credibility, which is beneficial to perfecting analysis of NMR in shale petrophysical measurement.

Claims

1. An evaluation method for hydrogen-bearing components, porosity and pore size distribution of organic-rich shale, comprising steps of: according to differences among NMR (nuclear magnetic resonance) T.sub.1-T.sub.2 maps of kerogen, oil-adsorbed kerogen, clay minerals of different water-containing conditions, shale, dry shale sample, oil-saturated shale sample and water-saturated shale sample, establishing a classification scheme for each hydrogen-hearing component and a quantitative characterization method for fluid components of the organic-rich shale; and because NMR signals of organic matters and clay mineral structural water exist in the organic-rich dry shale sample, with a T.sub.2 distribution of the organic-rich shale after being saturated with oil as a target and a T.sub.2 distribution of the dry shale sample as a basement, subtracting the basement, and obtaining a T.sub.2 distribution of oil in pores; and, based on the T.sub.2 distribution of oil in the pores, evaluating the porosity and the pore size distribution of the organic-rich shale.

2. The evaluation method for the hydrogen-bearing components, the porosity and the pore size distribution of the organic-rich shale, as recited in claim 1, particularly comprising steps of: through contrastive analysis of the NMR T.sub.1-T.sub.2 maps of kerogen, oil-adsorbed kerogen, clay minerals of different water-containing conditions, and organic-rich shales of different oil-containing/water-containing conditions, determining relaxation features of each hydrogen-bearing component, and establishing the classification scheme for signals of each hydrogen-bearing component and the quantitative characterization method for the fluid components of the organic-rich shale; processing the organic-rich shale with oil extracting and drying, and obtaining the dry shale sample; dividing the dry shale sample into two parts, wherein one part is processed with pressurization and oil saturation for an NMR experiment, and the other part is for experiments of porosity with a helium method, low temperature nitrogen adsorption, high-pressure mercury injection, and scanning electron microscope; and with the T.sub.2 distribution of the organic-rich shale after being saturated with oil as the target and the T.sub.2 distribution of the dry shale sample as the basement, subtracting the basement, and obtaining the T.sub.2 distribution of oil in the pores; based on the T.sub.2 distribution of oil in the pores, combined with a relationship between an NMR signal intensity and a volume of oil, evaluating the porosity of the organic-rich shale; and, combined with the experiments of low temperature nitrogen adsorption, high-pressure mercury injection, and scanning electron microscope, establishing an NMR characterization method for the pore size distribution of the organic-rich shale.

3. The evaluation method for the hydrogen-bearing components, the porosity and the pore size distribution of the organic-rich shale, as recited in claim 2, wherein: the kerogen and the oil-adsorbed kerogen are prepared through steps of: crushing an organic-rich shale sample to above 100 meshes; immersing in distilled water for 4 hours; successively processing with an acid treatment, an alkali treatment, and a pyrite treatment; thereafter adding dichloromethane, and stirring; after the dichloromethane is volatilized, obtaining the oil-adsorbed kerogen; processing the oil-adsorbed kerogen with chloroform extraction for 24 hours, and obtaining the kerogen; the clay minerals of different water-containing conditions are prepared through steps of: firstly saturating the clay mineral with water, and then drying for 24 hours respectively at 121° C. and 315° C., wherein: under a water saturation condition, a free water-containing clay mineral is obtained; after drying at 121° C. for 24 hours, an adsorbed water-containing clay mineral is obtained; and, after drying at 315° C. for 24 hours, a clay mineral merely containing structural water is obtained; and the organic-rich shales of different oil-containing/water-containing conditions are prepared through steps of: firstly processing an as-received shale sample with chloroform extraction for 24 hours; then extracting the shale sample after chloroform extraction with a ternary organic solution MAB having a relatively strong polarity for 24 hours, wherein a ratio of methyl alcohol, acetone and benzene in the tenary organic solution MAB is 15:15:70, so as to remove residual oil in the pores of the shale as far as possible; after ternary extraction, processing the shale sample with a high-temperature drying experiment until reaching a constant weight, wherein a drying temperature is set to he 315° C. and kept for 24 hours, so as to remove residual free water in the pores of the shale and residual bound/adsorbed water at surfaces of the pores, thereby obtaining the dry shale sample; and preserving the dry shale sample in a dryer at a room temperature.

4. The evaluation method for the hydrogen-bearing components, the porosity and the pore size distribution of the organic-rich shale, as recited in claim 2, wherein: the quantitative characterization method for the fluid components in the organic-rich shale comprises steps of: 1) calibrating an NMR signal intensity and a volume of free/bulk oil/water, particularly comprising steps of: configuring standard samples of oil and water with different volumes of 0.2 ml, 0.4 ml, 0.6 ml, 0.8 ml and 1.0 ml, and respectively processing with an NMR T.sub.2 distribution test; according to the volume and a corresponding NMR T.sub.2 distribution area of the free/bulk oil/water, establishing calibration formulas between the NMR signal intensity and the volume of the free/bulk oil and water that:
V.sub.O=k.sub.1×A.sub.O  (1);
V.sub.w=k.sub.2×A.sub.w  (2); wherein: in the formulas, V.sub.O is the volume of the free/bulk oil, and V.sub.w, is the volume of the free/bulk water, both in unit of ml; A.sub.O is the NMR T.sub.2 distribution area of the free/bulk oil, and A.sub.w, is the NMR T.sub.2 distribution area of the free/bulk water, both in unit of a.u.; k.sub.1 is a conversion coefficient between the NMR signal intensity and the volume of the free/bulk oil: and k.sub.2 is a conversion coefficient between the NMR signal intensity and the volume of the free/bulk water; and 2) calibrating an NMR signal intensity and mass of adsorbed oil, particularly comprising steps of: processing different dry shale samples; fitting relationships between the mass (m.sub.a-m.sub.0) and the NMR signal intensity (T.sub.2a-T.sub.20) of the adsorbed oil, wherein: m.sub.a and T.sub.2a are respectively mass and NMR T.sub.2 distribution signal intensit of the dry shale sample with the adsorbed oil; and, m.sub.0 and T.sub.0 are respectively mass and NMR T.sub.2 distribution signal intensity of the dry shale sample; and obtaining a calibration formula between the MIR signal intensity and the mass of the adsorbed oil that:
m.sub.a0=k.sub.a×A.sub.a0  (3); wherein: in the formula (3), m.sub.ao is the mass of the adsorbed oil, in unit of mg; A.sub.ao is an NMR T.sub.2 distribution area of the adsorbed oil, in unit of a.u.; and k.sub.a is a conversion coefficient between the NMR signal intensity and the mass of the adsorbed oil.

5. The evaluation method for the hydrogen-bearing components, the porosity and the pore size distribution of the organic-rich shale, as recited in claim 2, wherein: evaluation for the porosity of the organic-rich shale comprises steps of: acquiring an NMR T.sub.2 distribution of saturating oil and calculating the porosity, particularly comprising steps of: processing the oil-saturated shale sample with an NMR T.sub.2 distribution test, and obtaining an NMR T.sub.2 decay curve (S(t, sat)) of the oil-saturated shale sample; subtracting an NMR T.sub.2 decay curve (S(t, dry)) of the dry shale sample from the NMR T.sub.2 decay curve (S(t, sat)) of the oil-saturated shale sample, and obtaining a T.sub.2 decay curve (ΔS(t, oil)) of the saturating oil that: $\begin{array}{cc}S\left(t,\mathrm{dry}\right)={.Math.}_i{A}_i\exp \left(-\frac{t}{T_{2i}}\right);& \left(4\right)\\ S\left(t,\mathrm{sat}\right)={.Math.}_j{A}_j\exp \left(-\frac{t}{T_{2j}}\right);& \left(5\right)\\ \begin{array}{c}\Delta S\left(t,\mathrm{oil}\right)=S\left(t,\mathrm{sat}\right)-S\left(t,\mathrm{dry}\right)\\ ={.Math.}_k\Delta A_k\exp \left(-\frac{t}{T_{2k}}\right);\end{array}& \left(6\right)\end{array}$ wherein: in the formulas (4)-(6), S(t, dry) is an echo amplitude of the dry shale sample; S(t, sat) is an echo amplitude of the oil-saturated shale sample; ΔS(t, oil) is an echo amplitude of the saturating oil; A.sub.i is an amplitude of the dry shale sample when T.sub.2=T.sub.2i; A.sub.j is an amplitude of the oil-saturated shale sample when T.sub.2=T.sub.2j, ΔA.sub.k is an amplitude of the saturating oil when T.sub.2=T.sub.2k; t=n* TE, wherein n is number of echoes; i, j and k respectively represent orders of signal collection points, with a value of 1,2,3. . . n; and the NMR characterization method for the pore size distribution of the organic-rich shale comprises steps of: determining a calibration coefficient C; according to the formula (1), converting signal intensities corresponding to all T.sub.2 points in the NMR T.sub.2 distribution of the saturating oil to pore volumes; and, with a specified calibration coefficient C, converting a T.sub.2 relaxation time to a pore diameter through a formula of:
d=C×T.sub.2  (7); wherein: in the formula (7), d is the pore diameter, in unit of nm; T.sub.2 is an NMR transverse relaxation time, in unit of ms; and C is the calibration coefficient; with a horizontal axis of pore diameter and a vertical axis of dV/(dlogD), graphing a pore size distribution curve R.sub.NMR converted from the NMR T.sub.2 distribution of the saturating oil; superimposing a pore size distribution curve R.sub.MICP of high-pressure mercury injection with a pore size distribution curve R.sub.LTNA of low-temperature nitrogen adsorption; selecting a connection pore diameter r.sub.p at a pore diameter range of 10-100 nm, wherein dV/(dlogD) values of two pore size distribution curves at the point of connection pore diameter r.sub.p, are required to be roughly the same, ensuring that the pore number measured by a low-temperature nitrogen adsorption method and a high-pressure mercury injection method is almost identical at the pore diameter r.sub.p; remaining data points which are smaller than r.sub.p in the low-temperature nitrogen adsorption method and larger than r.sub.p in the high-pressure mercury injection method, and constructing a full pore size distribution curve R.sub.LTNA-MICP of the shale; superimposing curves of R.sub.LTNA-MICP and R.sub.NMR, and calculating an error value thereof through a formula of: $\begin{array}{cc}\begin{array}{c}Q=\frac{1}{n}\underset{i=1}{\overset{n}{.Math.}}\sqrt{{\left(R_{\mathrm{LTNA}-\mathrm{MICP}-i}-R_{\mathrm{NMR}-i}\right)}^2}\\ =\frac{1}{n}\underset{i=1}{\overset{n}{.Math.}}\sqrt{{\left(R_{\mathrm{LTNA}-\mathrm{MICP}-i}-C\times T_{2i}\right)}^2};\end{array}& \left(8\right)\end{array}$ wherein: in the formula (8), Q is the error.sup.-value; n is a number of data points in the R.sub.LTNA-MICP pore size distribution curve; R.sub.LTNA-MICP is an i.sup.th data point in the R.sub.LTNA-MICP pore size distribution curve; and R.sub.NMR-i is R.sub.NMR data corresponding to the i.sup.th data point in the R.sub.LTNA-MICP pore size distribution curve; when similarity of the curves of R.sub.LTNA-MICP and R.sub.NMR is closest, namely the error value is smallest, recording a. current value of the calibration coefficient C as a pore diameter calibration coefficient value of the NMR transverse relaxation time.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) FIG. 1 is a flow chart of an evaluation method for hydrogen-bearing components, porosity and pore size distribution of organic-rich shale according to the present invention.

(2) FIG. 2 shows NMR (nuclear magnetic resonance) T.sub.1-T.sub.2 maps of kerogen and oil-adsorbed kerogen according to the present invention.

(3) FIG. 3 shows features of an NMR T.sub.1-T.sub.2 map of free water in pores of montmorillonite after being saturated with water according to the present invention.

(4) FIG. 4 shows NMR T.sub.1-T.sub.2 maps of shale, dry shale sample, oil-saturated shale sample and water-saturated shale sample according to the present invention.

(5) FIG. 5 is an NMR T.sub.1-T.sub.2 map of each hydrogen-bearing component in lacustrine shale according to the present invention.

(6) FIG. 6 is a distribution feature diagram of NMR T.sub.2 distributions of free/bulk oil and free/bulk water with different volumes according to the present invention.

(7) FIG. 7 is a calibration diagram of NMR signals of the free/bulk oil and the free/bulk water according to the present invention.

(8) FIG. 8 is a relationship diagram between an NMR signal intensity and mass of adsorbed oil according to the present invention.

(9) FIG. 9 is a weight change curve diagram of samples tested at different pressurization saturation time periods according to the present invention.

(10) FIG. 10 is a comparison diagram between NMR T.sub.2 decay curves of the organic-rich dry shale sample and the oil-saturated shale sample according to the present invention.

(11) FIG. 11 is a comparison diagram between NMR T.sub.2 distributions of dry shale sample, oil-saturated shale sample, and saturating oil according to the present invention.

(12) FIG. 12 is a comparison diagram between pore size distributions of the organic-rich dry shale sample, obtained respectively by low-temperature nitrogen adsorption and high-pressure mercury injection, according to the present invention.

(13) FIG. 13 is a photo of the organic-rich shale by large-area high-resolution electron microscope imaging according to the present invention.

(14) FIG. 14 is a relationship diagram between an organic matter NMR signal intensity of the organic-rich shale and geochemical parameters according to the present invention.

(15) FIG. 15 is an NMR evaluation result diagram of oil saturation of the organic-rich shale according to the present invention.

(16) FIG. 16 is an NMR evaluation result diagram of the content of the adsorbed oil in the organic-rich shale according to the present invention.

(17) FIG. 17 is an NMR evaluation result diagram of the porosity of the organic-rich shale according to the present invention.

(18) FIG. 18 is an NMR characterization result diagram of the pore size distribution of the organic-rich shale according to the present invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

(19) In order to make the objects, technical solutions and advantages of the present invention clearer and more understandable, the present invention is further described in detail with the preferred embodiment. It should be understood that: the preferred embodiment described herein is merely for explaining the present invention, not for limiting the present invention.

(20) There exist deficiencies in the identification of the hydrogen-bearing components in the shale by the MnCl.sub.2-immersed shale or D.sub.2O-saturated shale, and the T.sub.2-D technology; the organic-rich shale expands after being saturated with water, and the pore structure is distorted; there exist deficiencies in the fluid detection of the micro-nano pores with the relatively short relaxation time in the organic-rich shale; and, the influences of the solid organic matter (kerogen) and mineral structural water on the porosity and pore size distribution characterization of the organic-rich shale are ignored.

(21) The present invention is further illustrated in detail as follows.

(22) The present invention provides an evaluation method for hydrogen-bearing components, porosity and pore size distribution of organic-rich shale, comprising steps of:

(23) with considering complexity of the hydrogen-bearing components in the organic-rich shale, according to differences among NMR (nuclear magnetic resonance) T.sub.1-T.sub.2 maps of kerogen, oil-adsorbed kerogen, clay minerals of different water-containing conditions, shale, dry shale sample, oil-saturated shale sample and water-saturated shale sample, establishing a classification scheme for each hydrogen-bearing component (kerogen, adsorbed oil, free oil, adsorbed water, free water, and mineral structural water) and a quantitative characterization method for fluid components of the organic-rich shale; and because NMR signals (enriched in organic matters and clay mineral structural water) which are relatively strong exist in the organic-rich dry shale sample, with a T.sub.2 distribution of the organic-rich shale after being saturated with oil as a target and a T.sub.2 distribution of the dry shale sample as a basement, subtracting the basement, and obtaining a T.sub.2 distribution of oil in pores; and based on the T.sub.2 distribution of oil in the pores, evaluating the porosity and the pore size distribution of the organic-rich shale.

(24) The present invention is further illustrated in detail as follows.

(25) The evaluation method for the hydrogen-bearing components, the porosity and the pore size distribution of the organic-rich shale based on the NMR can be divided into three parts, respectively the establishment of the NMR classification scheme for hydrogen-bearing components in the organic-rich shale, the NMR porosity evaluation of the organic-rich shale, and the NMR pore size distribution characterization of the organic-rich shale, particularly comprising steps of:

(26) through contrastive analysis of the NMR T.sub.1-T.sub.2 maps of kerogen, oil-adsorbed kerogen, clay minerals of different water-containing conditions, and organic-rich shales of different oil-containing/water-containing conditions, determining relaxation features of each hydrogen-bearing component, and establishing the classification scheme for signals of each hydrogen-bearing component in the organic-rich shale;

(27) processing the organic-rich shale with oil extracting and drying, and obtaining the dry shale sample; dividing the dry shale sample into two parts, wherein one part is processed with pressurization and oil saturation for an NMR experiment, and the other part is for experiments of porosity with a helium method, low-temperature nitrogen adsorption, high-pressure mercury injection, and scanning electron microscope; and

(28) with the T.sub.2 distribution of the organic-rich shale after being saturated with oil as the target and the T.sub.2 distribution of the dry shale sample as the basement, subtracting the basement, and obtaining the T.sub.2 distribution of oil in the pores; based on the T.sub.2 distribution of oil in the pores, combined with a relationship between an NMR signal intensity and a volume of oil, evaluating the porosity of the organic-rich shale; and, combined with the experiments of low-temperature nitrogen adsorption, high-pressure mercury injection, and scanning electron microscope, establishing an NMR characterization method for the pore size distribution of the organic-rich shale, as shown in FIG. 1.

(29) The used NMR device in the present invention is a MicroMR23-060H-1 NMR analyzer of Shanghai Niumag Corporation, wherein: a resonance frequency is 21.36 MHz; a magnet intensity is 0.28 T; a coil diameter is 25.4 mm; and a magnet temperature is 32° C. The test of T.sub.2 distribution adopts a CPMG sequence; and the test of T.sub.1-T.sub.2 map adopts an IR-CPMG sequence. Test parameters of the device are that: waiting time (TW) is 1000 ms; number of echoes (NECH) is 6000; echo time (TE) is 0.07 ms; P90 is 5.4 us; P180 is 10.6 us; number of scans (NS) is 64; and inversion time number (NTI) is 16.

(30) The present invention is further illustrated in detail as follows.

(31) Identification of Each Hydrogen-Bearing Component in Organic-Rich Shale

(32) With taking lacustrine organic-rich shale as an example and adopting a separation method, according to test results of the NMR T.sub.1-T.sub.2 maps of kerogen, oil-adsorbed kerogen, clay minerals of different water-containing conditions, shale, dry shale sample after extraction and drying, water-saturated shale, and oil-saturated shale, establishing the classification scheme for the signals of each hydrogen-bearing component in the shale; extracting NMR signal intensities of organic matters, oil and water in the shale; and, based on the relationship between the NMR signal intensity and the volume of oil/water, estimating a oil/water saturation value of the shale. Detailed technical solutions are described as follows.

(33) (1) Preparation of Kerogen and Oil-Adsorbed Kerogen

(34) Crushing the organic-rich shale sample to above 100 meshes; immersing in distilled water for 4 hours; successively processing with an acid treatment (successively with 6 mol/L hydrochloric acid, 6 mol/L hydrochloric acid and 40% hydrofluoric acid), an alkali treatment (with 0.5 mol/L sodium hydroxide), and a pyrite treatment (with 6 mol/L hydrochloric acid and arsenic-free zinc powder); thereafter adding dichloromethane, and stirring; after the dichloromethane is volatilized, obtaining the oil-adsorbed kerogen; processing the oil-adsorbed kerogen with chloroform extraction for 24 hours, and obtaining the kerogen.

(35) (2) Preparation of Clay Minerals of Different Water-Containing Conditions

(36) Because a content of illite-montmorillonite mixed-layer mineral in the organic-rich shale is relatively high, with montmorillonite as an example, firstly saturating the montmorillonite with water (free water and adsorbed water); and then drying for 24 hours respectively at 121° C. and 315° C.; wherein: under a water saturation condition, free water-containing montmorillonite is obtained; after drying at 121° C. for 24 hours, adsorbed water-containing illite is obtained; and, after drying at 315° C. for 24 hours, illite merely containing structural water is obtained.

(37) (3) Preparation of Shales of Different Oil-Containing/Water-Containing Conditions

(38) Because residual oil in the organic-rich shale is relatively heavy, firstly processing an as-received shale sample with chloroform extraction for 24 hours; then extracting the shale sample with a ternary organic solution MAB (a ratio of methyl alcohol, acetone and benzene is 15:15:70) having a relatively strong polarity for 24 hours, so as to remove the residual oil in the pores of the shale as far as possible; after ternary extraction, processing the shale sample with a high-temperature drying experiment until reaching a constant weight, wherein a drying temperature is set to be 315° C. and kept for 24 hours, so as to remove residual free water in the pores of the shale and residual bound/adsorbed water at surfaces of the pores, thereby obtaining the dry shale sample; and preserving the dry shale sample in a dryer (at a room temperature).

(39) According to the present invention, the dry shale sample after extraction and drying is placed into a vacuum pressurization saturation device; the dry shale sample is firstly vacuumized for 24 hours with a vacuum degree of 1×10.sup.−4 Pa; and, after finishing vacuumizing, processing the dry shale sample with pressurization and oil saturation or water saturation, wherein a pressurization saturation time is 36 hours.

(40) (4) NMR Relaxation Features of Each Hydrogen-Bearing Component in Shale

(41) The kerogen, oil-adsorbed kerogen, water-saturated montmorillonite, adsorbed water-containing illite, structural water-containing illite, shale, dry shale sample, oil-saturated shale and water-saturated shale, which are prepared through the above steps of (1)-(3), are processed with the NMR T.sub.1-T.sub.2 map test.

(42) The NMR T.sub.1-T.sub.2 maps of kerogen and oil-adsorbed kerogen are showed in FIG. 2. Under the mutual effect of homonuclear dipolar coupling, the transverse relaxation time of kerogen is relatively short, wherein: T.sub.2 is distributed between 0.01-0.65 ms; a main peak is at about 0.1 ms; T.sub.1 has a relatively wide distribution range and is mainly distributed between 0.65-100 ms; and a T.sub.1/T.sub.2 ratio is generally above 100. For the oil-adsorbed kerogen, T.sub.2 is mainly distributed between 0.05-2 ms; a main peak is located at about 0.15 ms; T.sub.1 is mainly distributed between 4.6-125 ms; and a T.sub.1/T.sub.2 ratio at the signal peak is about 155. Through subtracting the NMR T.sub.1-T.sub.2 map of the kerogen from the NMR T.sub.1-T.sub.2 map of the oil-adsorbed kerogen, the NMR T.sub.1-T.sub.2 map of the adsorbed oil is obtained (if a difference value is negative, set to be 0), wherein: for the adsorbed oil, T.sub.2 is mainly distributed between 0.22-1 ms; a main peak is distributed at 0.65 ms; T.sub.1 is mainly distributed between 10-125 ms; a T.sub.1/T.sub.2 ratio is between 25-200; and the T.sub.1/T.sub.2 ratio at the signal peak is about 50.

(43) Features of the NMR T.sub.1-T.sub.2 map of free water in the pores of montmorillonite after being saturated with water are showed in FIG. 3, wherein: T.sub.2 is mainly distributed between 0.22-1 ms; a main peak is located at 0.65 ms, a T.sub.1/T.sub.2 ratio is between 1-4.64; the T.sub.1/T.sub.2 ratio at the signal peak is about 1.94. After drying at 121° C., the interlayer water/free water is removed from montmorillonite, and montmorillonite is transformed into illite. For the adsorbed water-containing illite, T.sub.2 is between 0.01-0.11 ms; a main peak is located at about 0.072 ms; T.sub.1 is between 0.024-0.64 ms; a T.sub.1/T.sub.2 ratio is smaller than 10; and the T.sub.1/T.sub.2 ratio at the signal peak is about 3. After drying at 315° C., the adsorbed water at the surface of illite is removed, and the signal of structural water is detected by the NMR T.sub.1-T.sub.2 map test thereof. For the structural water, T.sub.2 is between 0.01-0.11 ms; a main peak is located at about 0.058 ms; T.sub.1 is between 0.058-26.83 ms; a T.sub.1/T.sub.2 ratio is smaller than 100; and the T.sub.1/T.sub.2 ratio at the signal peak is about 10.

(44) The NMR T.sub.1-T.sub.2 maps of shale, dry shale sample, oil-saturated shale sample, and water-saturated shale sample are showed in FIG. 4. The NMR T.sub.1-T.sub.2 map of shale is mainly distributed in five areas that: kerogen signal (T.sub.2<1 ms, T.sub.1/T.sub.2>100); adsorbed oil signal (0.22 ms<T.sub.2<1 ms, 25<T.sub.1/T.sub.2<100); free oil signal (T.sub.2>1 ms, 10<T.sub.1/T.sub.2<100); structural water signal (T.sub.2<0.22 ms, T.sub.1/T.sub.2<100); and adsorbed water signal (T.sub.2<0.22 ms, T.sub.1/T.sub.2<10). After processing the shale with chloroform extraction and drying at 315° C., compared with the NMR T.sub.1-T.sub.2 map of shale, the signal intensity of the free oil area (T.sub.2>1 ms, 10<T.sub.1/T.sub.2<100) in the NMR T.sub.1-T.sub.2 map of dry shale sample is obviously decreased. However, the oil signal still exists in the free oil area of the dry shale sample, which may be part of the residual oil existing in the isolated pores and not completely removed during the processes of chloroform extraction and drying. After being saturated with oil, the signal intensity of the free oil area (T.sub.2>1 ms, 10<T.sub.1/T.sub.2<100) is obviously increased. After being saturated with water, the signal intensities at the area of 0.22 ms<T.sub.2<1 ms and T.sub.1/T.sub.2<10 and the area of 1 ms<T.sub.2<10 ms and T.sub.1/T.sub.2<10 are obviously increased, indicating the free water. The signal intensity at the area of 0.22 ms<T.sub.2<1 ms and T.sub.1/T.sub.2<10 is same as that of the water-saturated montmorillonite (as shown in FIG. 3), may indicating water in the clay mineral intercrystalline pores. For the area of 1 ms<T.sub.2<10 ms and T.sub.1/T.sub.2<10, the T.sub.2 relaxation time is relatively long, reflecting the intergranular pores with the relatively large size.

(45) Classification Scheme for Signals of NMR T.sub.1-T.sub.2 Maps of Organic-Rich Shale

(46) According to the features of the NMR T.sub.1-T.sub.2 maps of kerogen, oil-adsorbed kerogen, clay minerals of different water-containing conditions, shale, dry shale sample after extraction and drying, oil-saturated shale sample, and water-saturated shale sample, the present invention provides the distribution range of each hydrogen-bearing component of the organic-rich shale in the NMR T.sub.1-T.sub.2 map, as shown in FIG. 5.

(47) (5) Quantitative Characterization for Fluid Content in Organic-Rich Shale

(48) 1) Calibrating NMR Signal Intensity and Volume of Free/Bulk Oil/Water

(49) Configuring standard samples of oil and water with different volumes (0.2 ml, 0.4 ml, 0.6 ml, 0.8 ml and 1.0 ml), and respectively processing with an NMR T.sub.2 distribution test, wherein the T.sub.2 distributions of free/bulk oil and free/bulk water are showed in FIG. 6; according to a volume and a corresponding NMR T.sub.2 distribution area of the free/bulk oil/water, establishing calibration formulas between the NMR signal intensity and the volume of the free/bulk oil and free/bulk water that:
V.sub.O=k.sub.1×A.sub.O  (1);
V.sub.w=k.sub.2×A.sub.w  (2);

(50) wherein: in the formulas, V.sub.O is a volume of the free/bulk oil, and V.sub.w is a volume of the free/bulk water, both in unit of ml; A.sub.O is an NMR T.sub.2 distribution area of the free/bulk oil, and A.sub.w is an NMR T.sub.2 distribution area of the free/bulk water, both in unit of a.u.; k.sub.1 is a conversion coefficient between the NMR signal intensity and the volume of the free/bulk oil; and k.sub.2 is a conversion coefficient between the NMR signal intensity and the volume of the free/bulk water.

(51) As shown in FIG. 7, according to the relationship between the NMR T.sub.2 distribution area and the volume of free/bulk oil and free/bulk water with different volumes, it is obtained that k.sub.1=0.9322 and k.sub.2=1.1131; the relationship between the NMR signal intensity and the volume of the free/bulk oil/water (formulas (1)-(2)) is for calculation of the volume of free/bulk oil and free/bulk water in the pores of the organic-rich shale.

(52) 2) Calibrating NMR signal intensity and mass of adsorbed oil Crushing the above dry shale sample to 80-100 meshes; then placing into the vacuum pressurization saturation device, and vacuumizing for 24 hours, wherein the vacuum degree is 1×10.sup.4 Pa; after finishing vacuumizing, processing the powdery dry shale sample with pressurization and oil saturation, wherein the pressurization saturation time is 36 hours.

(53) Heating the powdery dry shale sample after being saturated with oil with a constant temperature, wherein the heating temperature is 50° C.; weighing samples of different heating time periods, processing with the NMR T.sub.2 distribution test, and recording changes of the sample mass and the NMR T.sub.2 distribution, wherein: when the sample mass and the NMR T.sub.2 distribution is stable, it is considered that the dry shale sample with adsorbed oil is obtained; the current sample mass m.sub.a is recorded, and the NMR T.sub.2 distribution signal intensity thereof is T.sub.2a; heating the dry shale sample with adsorbed oil with a temperature of 315° C. for 48 hours, and obtaining the dry shale sample, wherein the current sample mass is recorded to be m.sub.0, and the current NMR T.sub.2 distribution signal intensity of the dry shale sample is T.sub.20.

(54) Processing different dry shale samples as above; fitting the relationships between the mass (m.sub.a-m.sub.0) and the NMR signal intensity (T.sub.2a-T.sub.20) of the adsorbed oil; and

(55) obtaining a calibration formula between the NMR signal intensity and the mass of the adsorbed oil that:
m.sub.a0=k.sub.a×A.sub.a0  (3);

(56) wherein: in the formula (3), m.sub.a is mass of the adsorbed oil, in unit of mg; A.sub.ao is an NMR T.sub.2 distribution area of the adsorbed oil, in unit of a.u.; and k.sub.a is a conversion coefficient between the NMR signal intensity and the mass of the adsorbed oil.

(57) As shown in FIG. 8, according to the relationships between the NMR T.sub.2 distribution area and the mass of adsorbed oil of different samples, it is obtained that k.sub.a=0.0102. The relationship between the NMR signal intensity and the mass of the adsorbed oil (formula (3)) is for calculation of the mass of the adsorbed oil in the pores of the organic-rich shale.

(58) 3) Calculating Fluid Content in Organic-Rich Shale

(59) According to the NMR T.sub.1-T.sub.2 map test results of shale, the classification scheme for the signals of the NMR T.sub.1-T.sub.2 maps of shale is established; the organic matter signal intensities are extracted from the NMR T.sub.1-T.sub.2 map, and contrasted with the pyrolysis experiment; the NMR signal intensities of free oil and free water are extracted from the NMR T.sub.1-T.sub.2 map, and the volumes of free oil and free water in the pores are respectively obtained through the formulas (1) and (2); combined with the sample porosity, the oil/water saturation value of shale is estimated; the NMR signal intensity of adsorbed oil is extracted from the NMR T.sub.1-T.sub.2 map, and with the formula (3), the content of adsorbed oil in the organic-rich shale is obtained.

(60) The evaluation for the porosity of the organic-rich shale is further described as follows.

(61) Evaluation for Porosity of Organic-Rich Shale

(62) In the evaluation of the porosity of the organic-rich shale, according to the differences between the NMR T.sub.2 distributions of the dry shale sample and the oil-saturated shale sample, with the T.sub.2 distribution of the organic-rich shale after being saturated with oil as the target and the T.sub.2 distribution of the dry shale sample as the basement, subtracting the basement, and obtaining the T.sub.2 distribution of oil in the pores; and, based on the T.sub.2 distribution of oil in the pores, combined with the relationship between the NMR signal intensity and the volume of oil (formula (1)), evaluating the porosity of the organic-rich shale. Detailed technical solutions are described as follows.

(63) (1) Preparation of Dry Shale Sample

(64) For the original shale taken back from the core library, because of the adsorption effect of rock mineral/kerogen and the accommodation effect of small pores, some water and oil which is relatively heavy are still remained in the pores. Therefore, if want to directly perform the helium porosity test and the pressurization saturation fluid processing, there mainly exist following problems. Firstly, the residual water and oil occupy the volume of pores, causing that the porosity obtained by the helium porosity test is smaller than the actual porosity. Secondly, the fluid-saturated shale sample is not saturated with the single fluid; the response features of the NMR signals of different fluids are different, and it will generate an error during conversion between the NMR signal and the fluid volume, resulting in the distortion of porosity. Thus, it is required to process the original shale with oil washing/extracting and drying.

(65) The preparation process of the dry shale sample has been illustrated in detail at the preparation of the shales of different oil-containing and water-containing conditions, and thus is not repeated herein.

(66) The dry shale sample after processing is made with the NMR T.sub.1-T.sub.2 map test, for checking whether the residual oil and water are completely removed from the dry shale sample after extraction and drying. As shown in FIG. 4, compared with the shale, only the solid organic matter (kerogen) signal (T.sub.1/T.sub.2>100, T.sub.2<1 ms) and the mineral structural water signal (T.sub.1/T.sub.2<100, T.sub.2<0.2 ms) are remained in the NMR T.sub.1-T.sub.2 map of the dry shale sample, and the residual oil signal and water signal disappear (T.sub.2>1 ms). If the NMR T.sub.1-T.sub.2 map signals of residual oil and water do not disappear, it is required to process the shale with extraction and drying again.

(67) The dry shale sample is processed with the NMR T.sub.2 distribution test, and the NMR T.sub.2 decay curve (S(t, dry)) of the dry shale sample is obtained.

(68) (2) NMR Porosity Calculation

(69) 1) Helium Porosity Measurement

(70) Placing the regular columnar dry shale sample (with a diameter of 2.5 cm) into the overburden pressure porosity and permeability measurement device, introducing helium into the device, and performing the helium porosity test in the common way, wherein the test process refers to the petroleum and natural gas industry standard, SY/T 6485-1999 Measurement method for porosity and permeability of rock under overburden pressure.

(71) 2) Pressurization and Oil Saturation Experiment of Dry Shale Sample

(72) In order to eliminate the hydration influence of water saturation on the shale sample, processing the dry shale sample after extraction and drying with pressurization and oil saturation, particularly comprising steps of: placing the dry shale sample into the vacuum pressurization saturation device; vacuumizing the dry shale sample for 24 hours with a vacuum degree of 1×10.sup.−4 Pa; after finishing vacuumizing, processing the dry shale sample with pressurization and oil saturation (with the example of n-dodecane, similarly hereinafter) for 60 hours, wherein a pressurization saturation pressure is 20 MPa; weighing the oil-saturated shale sample at different pressurization saturation time periods (12 hours, 24 hours, 36 hours, 48 hours and 60 hours); and, when the weight is stable (the change range of weights measured at two adjacent time periods is lower than 1%), obtaining the 100% oil-saturated shale sample. FIG. 9 is weight change curves of four samples tested at different pressurization saturation time periods, wherein: when the pressurization saturation time reaches 36 hours, the sample weight becomes stable, and it is considered that the 100% oil-saturated shale sample is obtained.

(73) 3) Acquirement of NMR T.sub.2 Distribution of Saturating Oil and Calculation of Porosity

(74) Under the premise that the NMR test parameters of the oil-saturated shale sample are consistent with that of the dry shale sample, processing the oil-saturated shale sample with the NMR T.sub.2 distribution test, and obtaining the NMR T.sub.2 decay curve (S(t, sat)) of the oil-saturated shale sample, as shown in FIG. 10. Therefore, through subtracting the NMR T.sub.2 decay curve (S(t, dry)) of the dry shale sample from the NMR T.sub.2 decay curve (S(t, sat)) of the oil-saturated shale sample, the T.sub.2 decay curve (ΔS(t, oil)) of saturating oil is obtained that:

(75) $\begin{array}{cc}S\left(t,\mathrm{dry}\right)={.Math.}_i{A}_i\exp \left(-\frac{t}{T_{2i}}\right);& \left(4\right)\\ S\left(t,\mathrm{sat}\right)={.Math.}_j{A}_j\exp \left(-\frac{t}{T_{2j}}\right);& \left(5\right)\\ \begin{array}{c}\Delta S\left(t,\mathrm{oil}\right)=S\left(t,\mathrm{sat}\right)-S\left(t,\mathrm{dry}\right)\\ ={.Math.}_k\Delta A_k\exp \left(-\frac{t}{T_{2k}}\right);\end{array}& \left(6\right)\end{array}$

(76) wherein: in the formulas (4)-(6), S(t, dry) is an echo amplitude of the dry shale sample; S(t, sat) is an echo amplitude of the oil-saturated shale sample; ΔS(t, oil) is an echo amplitude of saturating oil; A.sub.i is an amplitude of the dry shale sample when T.sub.2=T.sub.2i; A.sub.j is an amplitude of the oil-saturated shale sample when T.sub.2=T.sub.2j; ΔA.sub.k is an amplitude of saturating oil when T.sub.2=T.sub.2k; t=n*TE, wherein n is number of echoes; i, j and k respectively represent orders of signal collection points, with a value of 1, 2, 3 . . . n.

(77) According to the T.sub.2 decay curve ΔS(t, oil) of saturating oil, through mathematical subtracting, the T.sub.2 distribution of oil in the shale sample is obtained. As shown in FIG. 11, the NMR signals of the dry shale sample mainly come from the solid organic matter (kerogen) and clay mineral structural water, wherein the relaxation time thereof is relatively short and T.sub.2 is distributed between 0.01-1 ms in form of single peak. After being saturated with oil, two peaks occur in the NMR T.sub.2 distribution, wherein: the front peak keeps the form of dry shale sample, and only the signal intensity is increased; and, because of the influence of the pore size, the change amplitude of the front peak is far smaller than that of the rear peak. For the T.sub.2 distribution of saturating oil evaluated by the present invention, compared with the T.sub.2 distribution of the oil-saturated shale sample, the rear peak is much the same; the signal intensity at the front peak is lower, and the reduced signal is namely the signals of solid organic matter and clay mineral structural water in the dry shale sample.

(78) According to the NMR T.sub.2 distribution curve of saturating oil, the T.sub.2 distribution area of saturating oil is calculated; combined with the calibration formula (formula (1)) between the volume and the NMR signal of free oil, the volume of saturating oil is calculated, namely the pore volume of the shale sample; and the porosity is obtained through dividing the sample volume by the pore volume. The porosity of the organic-rich shale obtained by the NMR method is contrasted with the porosity tested by the helium method, so as to verify the accuracy and feasibility of the method.

(79) The present invention is further illustrated with the NMR characterization method for the pore size distribution of the organic-rich shale.

(80) NMR Characterization Method for Pore Size Distribution of Organic-Rich Shale

(81) In the pore size characterization and evaluation of the organic-rich shale, according to the differences between the NMR T.sub.2 distributions of dry shale sample and oil-saturated shale sample, with the T.sub.2 distribution of the organic-rich shale after being saturated with oil as the target and the T.sub.2 distribution of the dry shale sample as the basement, the T.sub.2 distribution of oil in the pores is obtained through subtracting the basement; and, based on the T.sub.2 distribution of oil in the pores, combined with experiments for pore size characterization of dry shale sample, such as low-temperature nitrogen adsorption, high-pressure mercury injection and large-area high-resolution electron microscope imaging, the NMR characterization method for the pore size distribution of the organic-rich shale is established.

(82) (1) Low-Temperature Nitrogen Adsorption and High-Pressure Mercury Injection Experiments

(83) Cutting and crushing the dry shale sample; firstly preparing into a sample with length, width and height of 1 cm 1 cm 1 cm, and performing the high-pressure mercury injection test (400 Mpa); according to the Washburn model, obtaining the pore size distribution curve R.sub.MICP of the pores with a diameter larger than 7.2 nm (with a horizontal axis of pore diameter and a vertical axis of dV/(dlogD), similarly hereinafter), wherein the operation process refers to the industry standard of SY/T 5346-2005; utilizing the powdered sample (80-100 meshes) after uniformly mixing, and performing the low-temperature nitrogen adsorption experiment; according to the BJH adsorption isotherm, obtaining the pore size distribution curve R.sub.LTNA of the pores with a diameter smaller than 100 nm, as shown in FIG. 12, wherein the operation process refers to the industry standard of GB/T 19587-2004.

(84) (2) Large-Area High-Resolution Electron Microscope Imaging Experiment

(85) Processing the surface of the vertical bedding of the regular sample block (1 cm×1 cm×1 cm) with mechanical polishing by the precise cutting-grinding integrated machine; fixing the sample after mechanical polishing on the aluminum T-shaped sample stage by the paraffin, polishing for 20 minutes at conditions of 5 KV and 2 mA with the argon ion polishing machine, then polishing at conditions of 2 KV and 2 mA for 10 minutes, alternately repeating for four times, and finishing polishing of the sample surface, wherein an included angle between the polished surface and the argon ion beam is 3°. In order to solve the problems of small vision filed of scanning electron microscope and heterogeneous sample, the present invention adopts the large-area high-resolution electron microscope imaging technology (AMICSCAN), for imaging of the polished surface of the sample at the low voltage of 1.2-0.8 KV and the low current of 200-80 pA, wherein the area of the imaging vision field is 300 um×800 um, as shown in FIG. 13. The pores are extracted through the threshold division method, the pore area is obtained, and the curve diagram of pore area verse pore diameter (dS/(dlogD)) is graphed.

(86) (3) Determining Calibration Coefficient C

(87) The pore size distribution curve of the present invention adopts the horizontal axis of pore diameter (width) and the vertical axis of dV/(dlogD), wherein the physical meaning of the vertical axis indicates the pore number corresponding to a certain pore diameter.

(88) Superimposing the pore size distribution curve R.sub.MICP of high-pressure mercury injection with the pore size distribution curve R.sub.LTNA of low-temperature nitrogen adsorption; selecting a connection pore diameter r.sub.p at a pore diameter range of 10-100 nm, wherein dV/(d log D) values of two pore size distribution curves at the point of connection pore diameter r.sub.p are required to be roughly the same, ensuring that the pore number measured by the low-temperature nitrogen adsorption method and the high-pressure mercury injection method is almost identical at the pore diameter r.sub.p; remaining data points which are smaller than r.sub.p in the low-temperature nitrogen adsorption method and larger than r.sub.p in the high-pressure mercury injection method, and constructing the full pore size distribution curve R.sub.LTNA-MICP of the shale.

(89) According to the formula (1), converting the signal intensities corresponding to every T.sub.2 point in the NMR T.sub.2 distribution of saturating oil (FIG. 11) into the pore volumes; and, with a specified calibration coefficient C, converting the T.sub.2 relaxation time to the pore diameter through a formula of:
d=C×T.sub.2  (7);

(90) wherein: in the formula (7), d is the pore diameter, in unit of nm; T.sub.2 is the NMR transverse relaxation time, in unit of ms; and C is the calibration coefficient;

(91) with the horizontal axis of pore diameter and the vertical axis of dV/(dlogD), graphing a pore size distribution curve R.sub.NMR converted from the NMR T.sub.2 distribution of the saturating oil; superimposing curves of R.sub.LTNA-MICP and R.sub.NMR, and calculating an error value thereof through a formula of:

(92) $\begin{array}{cc}\begin{array}{c}Q=\frac{1}{n}\underset{i=1}{\overset{n}{.Math.}}\sqrt{{\left(R_{\mathrm{LTNA}-\mathrm{MICP}-i}-R_{\mathrm{NMR}-i}\right)}^2}\\ =\frac{1}{n}\underset{i=1}{\overset{n}{.Math.}}\sqrt{{\left(R_{\mathrm{LTNA}-\mathrm{MICP}-i}-C\times T_{2i}\right)}^2};\end{array}& \left(8\right)\end{array}$

(93) wherein: in the formula (8), Q is the error value; n is a number of data points in the R.sub.LTNA-MICP pore size distribution curve; R.sub.LTNA-MICP-i is an i.sup.th data point in the R.sub.LTNA-MICP pore size distribution curve; and R.sub.NMR-i is R.sub.NMR data corresponding to the i.sup.th data point in the R.sub.LTNA-MICP pore size distribution curve;

(94) when similarity of the curves of R.sub.LTNA-MICP and R.sub.NMR is closest, namely the error value is smallest, recording a current value of the calibration coefficient C as a pore diameter calibration coefficient value of the NMR transverse relaxation time.

(95) Combined with the large-area high-resolution electron microscope imaging experiment, through analyzing and contrasting the NMR pore diameter conversion results calibrated by the low-temperature nitrogen adsorption and the high-pressure mercury injection with the curve diagram of pore area verse the pore diameter (dS/(dlogD)) obtained by the large-area high-resolution electron microscope imaging, the effect of NMR pore diameter calibration is verified.

(96) The present invention is further described combined with effects as follows.

(97) In the hydrogen-bearing component identification and fluid quantitative characterization of the organic-rich shale, the present invention takes 16 shale samples from Shahejie formation in Damintun Sag of Bohai Bay Basin, China as examples. Based on the above signal classification scheme for each hydrogen-bearing component in the shale and the quantitative characterization method for the fluid content in the organic-rich shale, the organic matter signal intensity of every sample is extracted from the T.sub.1-T.sub.2 map, and contrasted with the organic geochemical parameters (TOC, S1 and S2), as shown in FIG. 14. The organic matter signal intensity by the NMR test shows relatively good linear positive correlation with the parameters of TOC and S1+S2, further proving the feasibility of the classification scheme for each hydrogen-bearing component in the shale. Moreover, according to the present invention, the signal intensities of free oil and free water are respectively extracted from the T.sub.1-T.sub.2 maps; with utilizing the calibration relationships between the NMR signal intensity and the volume of free oil/water (formulas (1) and (2)), the volumes of free oil and free water are calculated; and, combined with the porosity measured by the NMR, the oil saturation and water saturation of shale are respectively estimated. With the oil saturation as the example, as shown in FIG. 15, the evaluation results of oil saturation of the present invention are roughly the same as that of the retort method. Meanwhile, the present invention extracts the signal intensity of adsorbed oil from the T.sub.1-T.sub.2 maps, and then the mass of adsorbed oil is estimated with utilizing the relationship between the NMR signal intensity and the mass of adsorbed oil (formula (3)). As shown in FIG. 16, the content of adsorbed oil shows a good relationship with the change ΔS.sub.2 (indicating the heavy oil) of the pyrolysis parameter S2 before and after oil extracting of the organic-rich shale.

(98) In the porosity evaluation of the organic-rich shale, the present invention takes 11 shales from Shahejie formation in Damintun Sag of Bohai Bay Basin, China as the examples. According to the above NMR measurement method for the porosity of the organic-rich shale, as shown in FIG. 17, compared with the helium porosity data, the porosity predicted by the T.sub.2 distribution of saturating oil of the present invention and the porosity by the helium method are uniformly distributed at two sides of the diagonal. Moreover, for the porosity which is obtained through the direct calculation of the oil-saturated organic-rich shale sample without removing the signal of dry shale sample (e.g., solid organic matter and mineral structural water), the conventional test results are generally higher than the porosity tested by the helium method; the porosity calculated through the NMR T.sub.2 distribution after removing the signal of dry shale sample by the present invention is closer to the test results by the helium method, having a higher reliability.

(99) In the characterization of pore size distribution of the organic-rich shale, the present invention takes the shale examples from Shahejie formation in Dongying Sag of Bohai Bay Basin, China as the examples. According to the above NMR characterization method for the pore size distribution of the organic-rich shale, the conversion coefficient of the NMR T.sub.2 time is calibrated together with the low-temperature nitrogen adsorption method and the high-pressure mercury injection method, as shown in FIG. 18. With the horizontal axis of pore width (diameter) and the vertical axis of dV/(dlogD), the connection point of the low-temperature nitrogen adsorption R.sub.LTNA curve and the high-pressure mercury injection R.sub.MICP curve is 25 nm; when the pore diameter smaller than 25 nm, the low-temperature nitrogen adsorption R.sub.LTNA curve is utilized; when the pore diameter larger than 25 nm, the high-pressure mercury injection R.sub.MICP curve is utilized, and the curve R.sub.LTNA-MICP is constructed. Through superimposing the curves of R.sub.LTNA-MICP and R.sub.NMR, when the error value of two curves is smallest, the conversion coefficient C of the NMR T.sub.2 time is calibrated to be 18. Compared with utilizing the curve diagram of pore area verse the pore diameter (dS/(dlogD)) obtained by the large-area high-resolution electron microscope imaging technology (AMICSCAN), the R.sub.NMR is closer in trend, further proving the reliability of the conversion coefficient calibrated together with the low-temperature nitrogen adsorption method and the high-pressure mercury injection method by the present invention. Additionally, compared with the pore size distribution results based on the NMR T.sub.2 distribution of oil-saturated shale sample, the pore diameter conversion results obtained through directly utilizing the NMR T.sub.2 distribution of saturating oil (obtained through subtracting the dry shale sample basement from the oil-saturated shale sample) by the present invention shows the high consistency with the low-temperature nitrogen adsorption experimental results in the small pores (<10 nm), which highlights the innovation of the present invention in the organic-rich shale's pore size distribution characterized by the NMR technique.

(100) The identification and quantitative characterization for hydrogen-bearing components and the evaluation for porosity and pore size distribution of the organic-rich shale have great significance in the exploration of shale oil and gas. Conventionally, in view of the deeper microscope research of the organic-rich shale reservoir and the accuracy improvement of the NMR device, the present invention utilizes the low echo time (TE=0.07 ms), considers the complexity of hydrogen-bearing components in the shale, establishes the classification scheme for each hydrogen-bearing component in the shale according to the differences among the NMR T.sub.1-T.sub.2 maps of kerogen, oil-adsorbed kerogen, clay minerals of different water-containing conditions, shale, dry shale sample, oil-saturated shale sample and water-saturated shale sample, and proposes the identification and quantitative characterization method for the hydrogen-bearing components in the organic-rich shale based on the NMR T.sub.1-T.sub.2 map. With considering the relatively high NMR signal intensity of the organic-rich dry shale sample (enriched in organic matters and mineral structural water), the present invention adopts the T.sub.2 distribution of the organic-rich shale after being saturated with oil as the target and the T.sub.2 distribution of the dry shale sample as the basement, obtains the T.sub.2 distribution of oil in the pores through subtracting the basement, and evaluates the porosity and pore size distribution of the organic-rich shale based on the T.sub.2 distribution of oil in the pores. The present invention provides the identification and quantitative characterization method for the hydrogen-bearing components and the evaluation method for the porosity and the pore size distribution of the organic-rich shale based on the NMR, which shows relatively high innovation and reliability in comparison with the conventional method. Therefore, the present invention is beneficial to perfecting the analysis of NMR in shale petrophysical measurement.

(101) The above-described is only the preferred embodiment of the present invention, not for limiting the present invention. Modifications, equivalent replacements, and improvements made within the spirit and principle of the present invention are all encompassed in the protection scope of the present invention.