Calibration method for representing dense sandstone pore size distribution by adopting nuclear magnetic resonance

Abstract

The invention relates to a calibration method for representing dense sandstone pore size distribution by adopting nuclear magnetic resonance; the method comprises the steps of measuring the rock porosity and the skeleton density; carrying out a low-temperature broken sample N2 absorption and desorption experiment, and carrying out a nuclear magnetic resonance test and a high pressure Hg injection test on a regular column sample in a saturated formation water state; converting pore volume obtained through N2 absorption into porosity components under different pore throat radiuses by using a capillary accumulated Hg inlet curve, and establishing a pore proportion summation curve by synthesizing low temperature N2-high pressure Hg injection; determining a best calibration coefficient by comparing the nuclear magnetic resonance pore proportion summation curves under the different C values to realize the conversion between nuclear magnetic resonance T2 spectrum and the pore throat radius; establishing a relation between parameters of the calibration coefficient C and a reflection pore-throat structure according to lithological characters; carrying out nuclear magnetic resonance conversion on dense sandstone reservoirs which are positioned in the same region and have the same lithological character. According to the method, the nuclear magnetic resonance T2 spectrum is calibrated by combining low temperature N2 absorption and a high pressure Hg injection experiment, and large pores, micropores and mesopores are calibrated, so that the distribution of different grades of pore sizes in dense sandstone can be effectively represented.

Description

technical field [0001] The invention relates to a calibration method for characterization of pore size distribution by nuclear magnetic resonance, in particular to a calibration method for characterization of tight sandstone pore size distribution by nuclear magnetic resonance. Background technique [0002] With the depletion of conventional oil and gas, unconventional oil and gas resources with huge resource potential have gradually attracted widespread attention and attention, especially tight sandstone oil and gas with the fastest growth rate. Tight reservoirs develop complex pore-throat systems at the micro-nano level, and the permeability values ​​are mostly less than 1mD. There is no obvious correlation between porosity and permeability. Tibetan. Fine characterization of the microscopic pore-throat structure of tight reservoirs is of great significance for the study of tight reservoir formation mechanisms, classification evaluation, and optimization of reservoir sweet...

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Problems solved by technology

At present, the characterization methods of pore size distribution mainly include fluid method, ray method and numerical simulation method. Among them, ray method and numerical simulation method are mainly used for qualitative description, and the test samples are small, so it is difficult to fully reflect the heterogeneity of tight reservoirs; The fluid method is an effective method to quantitatively characterize the pore size distribution, including high-pressure mercury injection, constant-speed mercury injection, low-temperature N 2 Experimental methods such as adsorption and nuclear magnetic resonance have certain limitations: high-pressure mercury intrusion can obtain capillary mercury intrusion curves, which reflect the pore throat radius and interconnected pore volume in rocks, but due to the fast measurement speed, at low mercury injection The measurement accuracy is low under high pressure, and it is easy to cause cracks under high mercury injection pressure, so the error is large when describing pores with a diameter of >1000nm and 2 Adsorption and desorption can obtain the pore diameter and pore volume of 100nm pore diameter is low; NMR T 2 Spectrum curves can reflect the distribution of pores at different levels, but the measured value is T 2 relaxation time, requires an effective calibration

Conventional reservoirs are dominated by large pores (>100nm), T 2 The shape of the mercury injection spectrum is basically consistent with the mercury injection curve; for tight sandstone reservoirs, the pores are mainly micropores and mesopores (2 There is a large difference between the spectrum and the mercury injection curve, and the calibration coefficient determined by this method has a large error

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