CN-122017192-A - Quantitative characterization method for carbon dioxide connectivity in shale cap layer

CN122017192ACN 122017192 ACN122017192 ACN 122017192ACN-122017192-A

Abstract

The invention relates to the technical field of carbon capture and sequestration, in particular to a quantitative characterization method of carbon dioxide connectivity in a shale cap layer, which comprises the steps of simulating stratum in-situ environment for the shale cap layer, developing a stepped injection pressure displacement test, collecting transverse relaxation time T 2 spectrums under different displacement pressures, constructing a T 2 -P c two-dimensional joint function based on capillary pressure P c and T 2 spectrums, calculating carbon dioxide connectivity coefficients of each pore-throat unit in the T 2 -P c two-dimensional map and the like. The method simulates the stratum in-situ environment through a multi-field coupling test system, combines injection pressure displacement and nuclear magnetic resonance technology, realizes synchronous acquisition of fluid occurrence state and fluidity under in-situ stress, and accurately distinguishes pore-throat units which are geometrically communicated but hydraulically isolated by constructing a T 2 -P c two-dimensional combined map and cooperatively characterizing pore structure and fluid migration characteristics, wherein a calculation result has obvious correlation with microCT test and relative permeability of CO 2 phase endpoints, and characterization accuracy is greatly improved.

Inventors

TIAN JIALI
XIE KUN
WANG HUIMIN
SHENG JINCHANG
CAO WEIJIA
YAN KUN
MEI JIE
YAN DA
BAI JIE

Assignees

东北石油大学

Dates

Publication Date: 20260512
Application Date: 20260126

Claims (7)

1. A method for quantitatively characterizing carbon dioxide connectivity in a shale cap layer, comprising the steps of: S1, preprocessing a shale cap layer sample to obtain a standard sample meeting test requirements; S2, placing the pretreated sample in a multi-field coupling test system, simulating the stratum in-situ environment, carrying out a stepped injection pressure displacement test, and synchronously acquiring transverse relaxation time T 2 spectrums under different displacement pressures in real time through a nuclear magnetic resonance technology; S3, constructing a T 2 -P c two-dimensional joint function representing the occurrence state and the fluidity of the pore fluid based on capillary pressure P c corresponding to different displacement pressures and the T 2 spectrum obtained in the step S2, and obtaining a T 2 -P c two-dimensional map; s4, based on the variable diameter capillary model, comprehensively considering capillary resistance, viscous resistance and inlet resistance, and calculating the carbon dioxide connectivity coefficient of each pore-throat unit in the T 2 -P c two-dimensional map; and S5, taking the signal intensity of each pore-throat unit in the T 2 -P c two-dimensional map as a weight, and carrying out weighted average on the carbon dioxide connectivity coefficient of the corresponding pore-throat unit to obtain the carbon dioxide connectivity in the shale cap layer.
2. The method of quantitative characterization of carbon dioxide connectivity in shale formations according to claim 1, wherein the pretreatment in step S1 comprises the steps of: S11, processing a shale sample into a standard cylindrical sample, wherein the geometric dimension of the standard cylindrical sample is phi 25mm multiplied by 20mm; s12, placing the processed sample in a 105 ℃ oven to be dried to constant weight, then degassing for at least 6 hours under minus 0.1MPa negative pressure through a vacuum saturation device, and injecting distilled water to be saturated for 24 hours under the application of 15MPa hydrostatic pressure; And S13, packaging the saturated sample, and ensuring the tightness in the test process.
3. The quantitative characterization method for carbon dioxide connectivity in shale overburden according to claim 1 is characterized in that in step S2, an in-situ stratum environment is simulated, specifically, a stratum pressure condition corresponding to a confining pressure and an axial pressure of 50 ℃ and a simulated CO 2 sealing depth of 800-2300 m is set, an injection pressure gradient of the stepped injection pressure displacement test is 1MPa, an injection pressure range is 8-14 MPa, and a T 2 spectrum is acquired after each pressure gradient is maintained for 12 hours to reach stress balance.
4. The method for quantitatively characterizing carbon dioxide connectivity in a shale cap layer according to claim 1, wherein the construction process of the T 2 -P c two-dimensional joint function in step S3 is: S31, subtracting the T 2 spectrums under different displacement pressures, eliminating the interference of rock matrix signals, and obtaining the T 2 distribution of the displaced movable water in different displacement pressure intervals; S32, converting the displacement pressure into a corresponding pore throat radius based on a Laplace equation, and establishing a mapping relation between the displacement pressure and the pore throat radius; s33, carrying out spline interpolation on the T 2 distribution of the movable water and the corresponding pore throat radius, constructing a T 2 -P c two-dimensional matrix, forming a T 2 -P c two-dimensional map, and representing the movable water volume of the corresponding pore throat unit by signal intensity in the map.
5. The method for quantitatively characterizing carbon dioxide connectivity in a shale cap layer according to claim 1, wherein the calculation of the carbon dioxide connectivity coefficient in step S4 is based on: Capillary resistance P c is calculated based on the Young-Laplace equation, and the calculation formula is: (1) wherein sigma is gas-liquid interfacial tension, theta is contact angle, and r t is pore throat radius; The viscous drag P v is derived based on the fluid flow equation in the variable diameter capillary by considering the thickness of the adsorbed water film on the pore wall surface, and the viscous drag expression is as follows: (2) Wherein v is the flow rate of the fluid in the capillary, r g is the gas flow radius, μ g is the gas phase viscosity, δ is the thickness of the bound water film, Q vd is the flow rate of the constant radius capillary model, μ is the fluid viscosity, and L is the pore length; The inlet resistance P e is deduced based on the momentum loss generated by the change of the fluid flow direction, and the calculation formula is as follows: (3) Wherein c=3; The total resistance is the superposition of capillary resistance, viscous resistance and inlet resistance: 。
6. the method of quantitatively characterizing carbon dioxide connectivity in a shale cap layer of claim 5, wherein carbon dioxide connectivity in a pore throat unit is defined as the ratio of water phase flux calculated by a constant radius to variable diameter capillary model: (4) Where α is the angle of change in streamline direction, r pj denotes the jth pore radius, r tr denotes the jth pore throat radius, and CI jr denotes carbon dioxide connectivity in pore throat units with pore radius r pj and pore throat radius r tr .
7. The method of quantitatively characterizing carbon dioxide connectivity in a shale cap according to claim 6, wherein the overall carbon dioxide connectivity indicator CI of the shale sample is calculated by the following formula: (5) (6) Where f jr is the signal intensity corresponding to each coordinate point (T 2 ,P c ) in the two-dimensional T 2 -P c distribution diagram, and represents the number or volume weight of pore throat units with a specific size, and D jr represents the product of the carbon dioxide phase connectivity of the T 2 -P c diagram and the signal intensity matrix data.

Description

Quantitative characterization method for carbon dioxide connectivity in shale cap layer Technical Field The invention relates to the technical field of carbon capture and sequestration, in particular to a quantitative characterization method of carbon dioxide connectivity in shale overburden. Background With the advancement of global carbon neutralization targets, carbon Capture and Sequestration (CCS) technology has become a key means of controlling carbon dioxide emissions, with deep salt water layers becoming the most potential geological sequestration vehicles by virtue of the tremendous sequestration capacity. The shale cap layer is used as a core packing barrier for CO 2 to pack, the tightness of the shale cap layer directly determines the long-term safety of a pack system, supercritical CO 2 moves upwards under the action of buoyancy and needs to be bound by a pore network and capillary force of the shale cap layer, and once the connectivity of pores is too high, the risk of CO 2 leakage is caused. However, the existing characterization method of the connectivity of CO 2 in the shale cap layer has some problems that the traditional method (such as micro CT and high-pressure mercury injection method) is only used for calculating connectivity based on a pore geometry topological structure, hydrodynamic factors such as fluid viscous resistance, gas-liquid interface effect, inlet resistance and the like are ignored, the actual connectivity of CO 2 is easily overestimated, the conventional test (such as centrifugation method) cannot simulate the in-situ stress condition of stratum, the high centrifugal force can damage the structural integrity of shale pores, the deviation of a test result from the actual geological environment is obvious, the one-dimensional nuclear magnetic resonance and other technologies can only characterize the pore size distribution, the coupling relation of the pore structure and the fluid flowability is difficult to cooperatively reflect, the pore units which are geometrically connected but hydraulically isolated cannot be accurately distinguished, the nano pore throat structure of the low-permeability shale is complex, the differential contribution of the multi-scale pores to the connectivity of CO 2 is difficult to be quantified by the existing method, and the evaluation of the sealing security lacks reliable basis. Therefore, developing a quantitative characterization method for CO 2 connectivity capable of coupling in-situ stress conditions, hydrodynamic resistance and pore structure characteristics has become an urgent need for guaranteeing the safe implementation of CCS engineering. Disclosure of Invention Aiming at the defects and problems, the invention provides a quantitative characterization method for carbon dioxide connectivity in a shale cap layer. The scheme adopted by the invention for solving the technical problems is that the quantitative characterization method for the connectivity of carbon dioxide in the shale cap layer comprises the following steps: S1, preprocessing a shale cap layer sample to obtain a standard sample meeting test requirements; S2, placing the pretreated sample in a multi-field coupling test system, simulating the stratum in-situ environment, carrying out a stepped injection pressure displacement test, and synchronously acquiring transverse relaxation time T 2 spectrums under different displacement pressures in real time through a nuclear magnetic resonance technology; S3, constructing a T 2-Pc two-dimensional joint function representing the occurrence state and the fluidity of the pore fluid based on capillary pressure P c corresponding to different displacement pressures and the T 2 spectrum obtained in the step S2, and obtaining a T 2-Pc two-dimensional map; s4, based on the variable diameter capillary model, comprehensively considering capillary resistance, viscous resistance and inlet resistance, and calculating the carbon dioxide connectivity coefficient of each pore-throat unit in the T 2-Pc two-dimensional map; and S5, taking the signal intensity of each pore-throat unit in the T 2-Pc two-dimensional map as a weight, and carrying out weighted average on the carbon dioxide connectivity coefficient of the corresponding pore-throat unit to obtain the carbon dioxide connectivity in the shale cap layer. Further, the preprocessing in step S1 includes the steps of: S11, processing a shale sample into a standard cylindrical sample, wherein the geometric dimension of the standard cylindrical sample is phi 25mm multiplied by 20mm; s12, placing the processed sample in a 105 ℃ oven to be dried to constant weight, then degassing for at least 6 hours under minus 0.1MPa negative pressure through a vacuum saturation device, and injecting distilled water to be saturated for 24 hours under the application of 15MPa hydrostatic pressure; And S13, packaging the saturated sample, and ensuring the tightness in the test process. Further, in step S2, the in-