| 主权项 |
1. A constant gradient field nuclear magnetic resonance (NMR) rock sample analysis method, characterized in that it comprises:
1) in a constant gradient field generated by a magnet, according to a saturated fluid in a sample under test, designing parameters comprising an echo train k, a pulse interval tau, the number of 180° pulses Ne, and a waiting time RD in a CGMF-CPMG pulse sequence to perform NMR measurement to acquire measurement data; the value of k is between 2 and 8, the value of tau is distributed between 150 μs and 20000 μs, the value of Ne is distributed between 128 and 30720, and the waiting time is distributed between 2000 ms and 12000 ms; 2) converting NMR data measured in Step 1) into a two-dimensional NMR spectrum D-T2; the data measured by adopting the CGMF-CPMG pulse sequence conforms to a multiexponential attenuation rule:bik=∑j=1m∑l=1pfljexp(-112γ2g2tauk2Dlti)exp(ti/T2j)+ɛik(5) wherein: i=1, . . . , nk, k=1, . . . , q, l=1, p, and j=1, . . . , m;i denotes the ith echo of the kth echo train, dimensionless;k denotes the kth echo train, dimensionless;l denotes the lth diffusion coefficient selected in advance, dimensionless;j denotes the jth relaxation time selected in advance, dimensionless;nk is the number of echoes of the kth echo train, dimensionless;q is the number of echo trains of different tauk, dimensionless;p denotes the number of diffusion coefficients selected in advance;m denotes the number of relaxation times selected in advance;bik denotes the amplitude of the ith echo of the kth echo train with the pulse interval being tauk, dimensionless;fijdenotes the amplitude when the diffusion coefficient is Dl, and the relaxation time is T2 j, dimensionless;γ is the gyromagnetic ratio, unit: MHz/T;G is the magnetic field gradient, unit: Gauss/cm;tauk, is the pulse interval of the kth echo train, unit: us;and performing inversion on Equation (5) by adopting an improved singular value de composition method to acquire the two-dimensional NMR spectrum D-T2; 3) performing measurement and inversion on a constant gradient field standard sample using Step 1) and Step 2) to obtain the two-dimensional NMR spectrum D-T2 of the standard sample; taking 12 constant gradient field NMR standard samples, porosities being 0.5%, 1%, 2%, 3%, 6%, 9%, 12%, 15%, 18%, 21%, 24%, and 27%, respectively, for each time of calibration, select at least 5 of the 12 for measurement and inversion to obtain two-dimensional NMR spectra of standard samples with different porosities, then performing volume integration on the two-dimensional NMR spectra to obtain NMR signals of the standard samples; the ratio between the NMR signal and the volume of the standard sample being the NMR signal of a unit volume; and performing linear fitting on porosity and the NMR signal of the unit volume to obtain a relationship line thereof:
y=ax+b (8)wherein y represents the NMR signal quantity of a unit volume, x represents an NMR porosity (%), a represents a slope, and b represents a Y-intercept;when measuring the rock sample, measuring the NMR signal of a unit volume of the rock sample to compute the porosity of a rock sample; 4) measuring the rock sample using Step 1) and Step 2), acquiring a fluid two-dimensional NMR spectrum D-T2 in the rock sample, performing fluid types identification according to a practically measured two-dimensional NMR spectrum D-T2 of the rock sample; wherein the diffusion coefficient of water is a constant, and is related to the temperature; the diffusion coefficient of gas is related to the temperature and pressure; and a linear relationship exists between the diffusion coefficient and relaxation time of crude oil;
Dw(T2)=Dw(T) (9)Dg(T2)=Dg(T, P) (10)Do=αT2 (11)establishing, by a constant gradient field NMR rock sample analyzer, according to these NMR attributes of diffusion coefficient and relaxation time of oil, gas and water, a two-dimensional NMR spectrum explanation template, and dividing oil, gas and water according to the positions of the practically measured two-dimensional NMR spectrum D-T2 of the rock sample in the explanation template to rapidly identify fluid types; 5) computing the porosity, permeability, oil saturation, movable fluid saturation, crude oil coefficient of the rock sample according to the two-dimensional NMR spectrum D-T2 of fluids in the rock sample acquired in Step 4); a) performing volume integration through the two-dimensional NMR spectrum of the rock sample, introducing a constant gradient field NMR calibration line according to Step 3), and computing the NMR porosity of the rock sample; b) computing the permeability of the rock sample according to the NMR porosity and irreducible water saturation:Knmr=(ϕnmrC)4(100%-SwiSwi)2(12) wherein, Knmr is NMR permeability, Φnmr is NMR porosity, Swi is irreducible water saturation, and C is the coefficient to be determined; c) identifying fluid types rapidly according to the two-dimensional NMR spectrum explanation template established in Step 4), distinguishing oil and water; selecting the area of oil in the two-dimensional NMR spectrum with a mouse, computing, by the system, automatically the ratio between the volume integral of the selected area and the total volume integral of the two-dimensional NMR spectrum, and acquiring oil saturation; similarly, obtaining oil, gas and water saturation, respectively; d) comprehensively judging and selecting a movable fluid area according to a movable fluid T2 cutoff line, a diffusion coefficient line, an oil phase relationship line in the two-dimensional NMR spectrum explanation template established in Step 4), computing, by the system, automatically the ratio between the volume integral of the selected area and the total volume integral to acquire movable fluid saturation; e) when the rock sample contains crude oil with a high viscosity, measuring that the NMR signal of a unit volume of rock sample is small, causing offsets of different degrees to parameters of the porosity, permeability, movable fluid saturation and oil saturation of a rock sample, wherein calibration is required; the crude oil coefficient is ratio between the signal of a unit volume of constant gradient field NMR standard sample and the NMR signal of a unit volume of crude oil:η=AStandardSample/ϕStandardSampleACrudeOil(13) wherein: η is the crude oil coefficient, AStandard Sample is the NMR signal quantity of a unit volume of the standard sample, ΦStandard Sample is the porosity of and standard sample, and ACrude Oil is the NMR signal quantity of a unit volume of the measured crude oil; 6) the slicing thickness of the constant gradient field NMR rock sample analyzer being 0.3 cm, and according to Step 1) to Step 5), performing single slice scanning on a rock sample to acquire partial oil and water saturation of a rock sample; at the same time, repeating Step 1) to Step 5) to perform continuous slice scanning on the rock sample to acquire axial oil and water saturation distribution and movable fluid saturation distribution of the rock sample, so as to perform better realtime reservoir evaluation and fluid identification. |
