CN108469406B - Method and device for determining non-dimensional time model of rock core imbibition - Google Patents
Method and device for determining non-dimensional time model of rock core imbibition Download PDFInfo
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- 238000005213 imbibition Methods 0.000 title claims abstract description 106
- 238000000034 method Methods 0.000 title claims abstract description 60
- 239000011435 rock Substances 0.000 title claims abstract description 47
- 239000011148 porous material Substances 0.000 claims abstract description 101
- 230000035699 permeability Effects 0.000 claims abstract description 74
- 238000012360 testing method Methods 0.000 claims abstract description 15
- 238000002791 soaking Methods 0.000 claims description 19
- 230000015572 biosynthetic process Effects 0.000 claims description 17
- 230000006870 function Effects 0.000 claims description 15
- 238000011144 upstream manufacturing Methods 0.000 claims description 13
- 238000009736 wetting Methods 0.000 claims description 12
- 238000004590 computer program Methods 0.000 claims description 6
- 239000011159 matrix material Substances 0.000 claims description 3
- 238000012545 processing Methods 0.000 claims description 3
- 230000035515 penetration Effects 0.000 claims 3
- 238000002474 experimental method Methods 0.000 description 15
- 239000012530 fluid Substances 0.000 description 9
- 239000003350 kerosene Substances 0.000 description 9
- 230000008569 process Effects 0.000 description 9
- 230000006872 improvement Effects 0.000 description 8
- 230000002269 spontaneous effect Effects 0.000 description 6
- 238000010586 diagram Methods 0.000 description 5
- 238000005516 engineering process Methods 0.000 description 5
- 230000008859 change Effects 0.000 description 4
- 238000011161 development Methods 0.000 description 4
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- VYPSYNLAJGMNEJ-UHFFFAOYSA-N silicon dioxide Inorganic materials O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 description 3
- 238000005481 NMR spectroscopy Methods 0.000 description 2
- WCUXLLCKKVVCTQ-UHFFFAOYSA-M Potassium chloride Chemical compound [Cl-].[K+] WCUXLLCKKVVCTQ-UHFFFAOYSA-M 0.000 description 2
- 238000001035 drying Methods 0.000 description 2
- 230000000694 effects Effects 0.000 description 2
- 239000000203 mixture Substances 0.000 description 2
- 238000001228 spectrum Methods 0.000 description 2
- 238000005406 washing Methods 0.000 description 2
- YZCKVEUIGOORGS-OUBTZVSYSA-N Deuterium Chemical compound [2H] YZCKVEUIGOORGS-OUBTZVSYSA-N 0.000 description 1
- 239000007864 aqueous solution Substances 0.000 description 1
- 230000005540 biological transmission Effects 0.000 description 1
- 229910001748 carbonate mineral Inorganic materials 0.000 description 1
- 239000002734 clay mineral Substances 0.000 description 1
- 238000004891 communication Methods 0.000 description 1
- 230000008021 deposition Effects 0.000 description 1
- 238000013461 design Methods 0.000 description 1
- 229910052805 deuterium Inorganic materials 0.000 description 1
- 239000012153 distilled water Substances 0.000 description 1
- 239000010433 feldspar Substances 0.000 description 1
- 230000005055 memory storage Effects 0.000 description 1
- 230000003287 optical effect Effects 0.000 description 1
- 239000001103 potassium chloride Substances 0.000 description 1
- 235000011164 potassium chloride Nutrition 0.000 description 1
- 238000002203 pretreatment Methods 0.000 description 1
- 239000000047 product Substances 0.000 description 1
- 230000000750 progressive effect Effects 0.000 description 1
- 238000005086 pumping Methods 0.000 description 1
- 239000010453 quartz Substances 0.000 description 1
- 238000011084 recovery Methods 0.000 description 1
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- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N15/00—Investigating characteristics of particles; Investigating permeability, pore-volume or surface-area of porous materials
- G01N15/08—Investigating permeability, pore-volume, or surface area of porous materials
- G01N15/088—Investigating volume, surface area, size or distribution of pores; Porosimetry
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N15/00—Investigating characteristics of particles; Investigating permeability, pore-volume or surface-area of porous materials
- G01N15/08—Investigating permeability, pore-volume, or surface area of porous materials
- G01N15/082—Investigating permeability by forcing a fluid through a sample
- G01N15/0826—Investigating permeability by forcing a fluid through a sample and measuring fluid flow rate, i.e. permeation rate or pressure change
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Abstract
The embodiment of the application discloses a method and a device for determining a dimensionless time model of rock core imbibition. The method provides target parameter information obtained when a core sample of a target oil reservoir is subjected to gas logging permeability test under specified net pressure; the method comprises the following steps: determining the gas logging permeability of the core sample under the specified net pressure according to the target parameter information; determining the average pore radius of the core sample under the specified net pressure according to the gas logging permeability, and establishing the correlation between the average pore radius and the net pressure according to the average pore radius of the core sample under the specified net pressure; and determining a rock core imbibition dimensionless time model of the target oil reservoir based on the correlation between the average pore radius and the net pressure. According to the technical scheme provided by the embodiment of the application, the accuracy of the established rock core imbibition dimensionless time model can be improved.
Description
Technical Field
The application relates to the technical field of oil reservoir development, in particular to a method and a device for determining a rock core imbibition dimensionless time model.
Background
The Ordos basin extended compact reservoir has low porosity, low permeability, small seepage passage (micro-nano pore throat development), low pressure coefficient, and the existing development technology is difficult to solve the problems of low yield, fast decrement, difficult energy supplement, low recovery ratio and the like. At present, the main ways of improving the development effect of such tight oil reservoirs are two: firstly, the scale of transformation is improved, namely a complex seam net is formed through large-scale volume fracturing, and the seepage distance is shortened; and secondly, after the well is pressed, soaking and replacing the well, and the oil displacement efficiency is improved through imbibition and displacement.
At present, partial field test results show that the fracturing fluid does not flow back after the volume of the water-wet oil reservoir is transformed, but is stewed for a period of time, so that the yield is improved. For the determination of the soaking time, an effective mode is to develop a spontaneous imbibition simulation experiment to simulate the whole shut-in process, and the corresponding time when the imbibition displacement production degree reaches the highest is the soaking time of the laboratory scale, namely the soaking time of the core scale. And then, based on the spontaneous imbibition dimensionless time model, applying the result of the core scale to the oil reservoir scale, and determining the soaking time of the oil reservoir scale. However, the existing spontaneous imbibition experiment is performed under normal pressure, and a spontaneous imbibition dimensionless time model is established under normal pressure, so that the spontaneous imbibition experiment result under normal pressure is applied to the oil reservoir scale of an actual oil reservoir with certain overburden pressure based on the spontaneous imbibition dimensionless time model under normal pressure, which may cause large deviation of the obtained oil reservoir scale, and therefore, it is necessary to develop a new method for determining the rock core imbibition dimensionless time model to improve the accuracy of the established rock core imbibition dimensionless time model, so as to apply the rock core scale result to the oil reservoir scale more accurately.
Disclosure of Invention
The embodiment of the application aims to provide a method and a device for determining a rock core imbibition non-dimensional time model so as to improve the accuracy of the established rock core imbibition non-dimensional time model.
In order to solve the above technical problem, an embodiment of the present application provides a method and an apparatus for determining a non-dimensional time model of core imbibition, which are implemented as follows:
a method for determining a core imbibition dimensionless time model provides target parameter information obtained when a core sample of a target oil reservoir is subjected to a gas logging permeability test under specified net pressure; the method comprises the following steps:
determining the gas logging permeability of the core sample under the specified net pressure according to the target parameter information;
determining the average pore radius of the core sample under the specified net pressure according to the gas logging permeability, and establishing the correlation between the average pore radius and the net pressure according to the average pore radius of the core sample under the specified net pressure;
and determining a rock core imbibition dimensionless time model of the target oil reservoir based on the correlation between the average pore radius and the net pressure.
In a preferred scheme, determining the gas logging permeability of the rock core sample under the specified net pressure according to the slope of a pressure attenuation semilogarithmic curve, the volume of an upstream cavity and the volume of a downstream cavity in the target parameter information; wherein the pressure decay semi-logarithmic curve slope, the upstream cavity volume, and the downstream cavity volume are associated with the specified net pressure.
In a preferred embodiment, the core sample is cylindrical, and the gas permeability of the core sample under the specified net pressure is determined by using the following formula:
wherein k isaThe gas permeability of the core sample is expressed in millidarcy, α represents the slope of the pressure decay semilog curve in megapascals per second, mugDenotes the gas viscosity in MPa.s.cgExpressed as gas compressibility in MPa-1，VuAnd VdRespectively representing the volume of the upstream cavity and the volume of the downstream cavity, wherein L represents the height of the core sample and is expressed in centimeters, and A represents the sectional area along the direction vertical to the column axis of the core sample and is expressed in square centimeters.
In a preferred embodiment, determining the average pore radius of the core sample at the specified net pressure comprises:
determining a gas slippage factor of the core sample according to the gas logging permeability;
determining an average pore radius of the core sample at the specified net pressure based on the gas slip factor.
In a preferred embodiment, determining the gas slip factor of the core sample at the specified net pressure comprises:
respectively determining a plurality of gas logging permeabilities of the core sample under a plurality of specified net pressures, obtaining a plurality of gas inlet and outlet average pressures corresponding to the specified net pressures, and taking one gas logging permeability corresponding to the inverse of one gas inlet and outlet average pressure as a data point to obtain a plurality of data points;
performing linear fitting processing on the plurality of data points to determine a fitted straight line between the gas permeability and the inverse of the average pressure at the gas inlet and outlet;
and determining a gas slip factor of the core sample at the specified net pressure according to the slope and the intercept in the fitted straight line.
In a preferred scheme, the gas slip factor of the core sample is determined by adopting the following formula:
b＝k∞×a2
k∞＝a1
wherein b represents a gas slip factor, k, of the core sample∞The permeability in grams of the core sample is expressed in millidarcy, a1Representing the slope of said fitted line, a2Represents the intercept of the fitted line.
Preferably, the average pore radius of the core sample at the specified net pressure is determined using the following formula:
wherein r represents the average pore radius of the core sample in microns, c represents a proportionality constant, λ represents the gas molecule mean free path in microns, and P representspThe average pressure of a gas inlet and a gas outlet corresponding to the specified net pressure is expressed in megapascals, b represents a gas slip factor of the rock core sample, mugGas viscosity in MPa.s, RgDenotes the gas constant in joules/(kelvin-mole) T denotes absolute temperature in kelvin, M denotes the molar mass of the gas molecule.
In a preferred embodiment, the establishing the correlation between the average pore radius and the net pressure includes:
respectively determining a plurality of average pore radii of the rock core sample under a plurality of specified net pressures, and taking one average pore radius corresponding to one specified net pressure as a data point to obtain a plurality of data points;
and fitting the plurality of data points to establish the correlation between the average pore radius and the net pressure.
In the preferred scheme, the rock core imbibition dimensionless time model of the target oil reservoir is determined by the following formula:
wherein, tDRepresenting a dimensionless time in the core imbibition dimensionless time model; r (p) represents the average pore radius as a function of net pressure determined from the correlation of average pore radius to net pressure; t represents imbibition time; c represents the fixation coefficient of the core sample, σ represents the interfacial tension between the wetting and non-wetting phases, μwDenotes the viscosity of the wetting phase, μoRepresents the viscosity of the non-wetting phase; l isCRepresenting a characteristic length, V, of the core samplebRepresents the volume of matrix in the core sample, AiDenotes the area of the imbibition contact surface in the i-th imbibition direction,/AiThe distance from the imbibition contact surface to the closed boundary in the i-th imbibition direction at the imbibition front edge is shown, and n represents the number of imbibition directions.
In a preferred scheme, the method is further provided with the average pore radius, the characteristic length and the fixed coefficient of the target oil reservoir under the specified stratum covering pressure; wherein the specified formation overburden pressure is the same as the specified net pressure; the method further comprises the following steps:
determining a soak time of the core sample at the specified net pressure;
and determining the soaking time of the target oil reservoir under the specified stratum pressure based on the soaking time of the core sample, a core imbibition dimensionless time model of the target oil reservoir, and the average pore radius, the characteristic length and the fixed coefficient of the target oil reservoir.
In the preferred scheme, the soaking time of the target oil reservoir under the specified stratum pressure is determined by the following formula:
wherein (t)shut-in)fieldIndicating the soaking time of the target oil reservoir under the specified stratum covering pressure, (t)shut-in)labRepresenting a shut-in time of the core sample at the specified net pressure; cfield、rfieldAnd (L)C)fieldRespectively representing the fixed coefficient, the average pore radius and the characteristic length of the target oil reservoir under the specified formation overburden pressure; clab、rlabAnd (L)C)labRespectively representing the fixed coefficient, average pore radius, and characteristic length of the core sample at the specified net pressure.
A device for determining a core imbibition dimensionless time model provides target parameter information obtained when a core sample of a target oil reservoir is subjected to a gas logging permeability test under specified net pressure; the device comprises: the system comprises a gas permeability determining module, an incidence relation establishing module and a dimensionless time model determining module; wherein,
the gas permeability determining module is used for determining the gas logging permeability of the rock core sample under the specified net pressure according to the target parameter information;
the incidence relation establishing module is used for determining the average pore radius of the rock core sample under the specified net pressure according to the gas logging permeability, and establishing the incidence relation between the average pore radius and the net pressure according to the average pore radius of the rock core sample under the specified net pressure;
and the dimensionless time model determining module is used for determining a rock core imbibition dimensionless time model of the target oil reservoir based on the incidence relation between the average pore radius and the net pressure.
An apparatus for determining a dimensionless time model of core imbibition comprises a memory, a processor, and a computer program stored on the memory, wherein the memory stores target parameter information obtained when a gas permeability test is performed on a core sample of a reservoir of interest under a specified net pressure, and the computer program is executed by the processor to perform the following steps:
determining the gas logging permeability of the core sample under the specified net pressure according to the target parameter information;
determining the average pore radius of the core sample under the specified net pressure according to the gas logging permeability, and establishing the correlation between the average pore radius and the net pressure according to the average pore radius of the core sample under the specified net pressure;
and determining a rock core imbibition dimensionless time model of the target oil reservoir based on the correlation between the average pore radius and the net pressure.
According to the technical scheme provided by the embodiment of the application, the embodiment of the application provides a method and a device for determining a rock core imbibition dimensionless time model, the influence of formation overburden pressure is considered, so that the gas logging permeability of a rock core sample under the specified net pressure is determined, the average pore radius of the rock core sample under the specified net pressure can be determined according to the gas logging permeability, and the incidence relation between the average pore radius and the net pressure can be established according to the average pore radius of the rock core sample under the specified net pressure; and finally, determining the core imbibition dimensionless time model of the target oil reservoir based on the correlation between the average pore radius and the net pressure, so that the core imbibition dimensionless time model is established under the net pressure same as the formation overburden pressure, thus the accuracy of the established core imbibition dimensionless time model can be improved, and the core scale result can be more accurately applied to the oil reservoir scale.
Drawings
In order to more clearly illustrate the embodiments of the present application or the technical solutions in the prior art, the drawings needed to be used in the description of the embodiments or the prior art will be briefly introduced below, it is obvious that the drawings in the following description are only some embodiments described in the present application, and for those skilled in the art, other drawings can be obtained according to the drawings without any creative effort.
FIG. 1 is a flow chart of an embodiment of a method of determining a dimensionless time model for core imbibition according to the present application;
fig. 2 is a schematic structural diagram of a pressurized imbibition experimental device in the embodiment of the application.
FIG. 3 is a graphical representation of gas permeability as a function of the inverse of the mean pressure at the fluid inlet and outlet in an embodiment of the present application;
FIG. 4 is a graphical representation of the average pore radius as a function of a specified net pressure in an embodiment of the present application;
FIG. 5 is a graph illustrating the extent of production of kerosene in a core sample as a function of imbibition time in an example of the present application;
FIG. 6 is a schematic diagram illustrating the components of one embodiment of an apparatus for determining a dimensionless time model of core imbibition according to the present application;
fig. 7 is a schematic structural diagram illustrating a composition of another embodiment of the apparatus for determining a dimensionless time model of core imbibition according to the present application.
Detailed Description
The embodiment of the application provides a method and a device for determining a dimensionless time model of rock core imbibition.
In order to make those skilled in the art better understand the technical solutions in the present application, the technical solutions in the embodiments of the present application will be clearly and completely described below with reference to the drawings in the embodiments of the present application, and it is obvious that the described embodiments are only a part of the embodiments of the present application, and not all of the embodiments. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present application.
The embodiment of the application provides a method for determining a dimensionless time model of core imbibition. The method for determining the core imbibition dimensionless time model provides target parameter information obtained when a core sample of a target oil reservoir is subjected to a gas logging permeability test under specified net pressure.
In this embodiment, the reservoir of interest may refer to a reservoir whose soak time has not been determined, and the reservoir of interest may be a tight reservoir, such as a tight reservoir in the Chongqing oilfield element 284 block of Orldos basin. The core sample of the reservoir of interest may be a tight core sample. The core sample may be cylindrical in shape.
In this embodiment, the target parameter information may be obtained by performing a gas permeability test on a core sample of the target oil reservoir under a specified net pressure by a pulse attenuation method. Wherein the specified net pressure may be the same as the formation overburden pressure of the reservoir of interest. The specified net pressure may represent the confining pressure minus the fluid inlet-outlet mean pressure during the pulse decay test; the fluid inlet and outlet mean pressure represents half of the sum of the fluid inlet pressure and the fluid outlet pressure. The range of values for the specified net pressure may include: 0 to 25 MPa.
In this embodiment, the target parameter information may include a slope of a pressure decay semilogarithmic curve, an upstream cavity volume, and a downstream cavity volume measured at the specified net pressure.
FIG. 1 is a flow chart of an embodiment of a method for determining a dimensionless time model for core imbibition according to the present application. As shown in fig. 1, the method for determining the dimensionless time model of core imbibition includes the following steps.
Step S101: and determining the gas logging permeability of the core sample under the specified net pressure according to the target parameter information.
In this embodiment, the gas permeability of the core sample at the specified net pressure may be determined according to a slope of a pressure decay semilogarithmic curve, an upstream cavity volume, and a downstream cavity volume in the target parameter information. Wherein the pressure decay semi-logarithmic curve slope, the upstream cavity volume, and the downstream cavity volume are associated with the specified net pressure.
In this embodiment, the core sample is cylindrical in shape, and the gas permeability of the core sample at the specified net pressure may be determined using the following formula:
wherein k isaThe gas permeability of the core sample is expressed in millidarcy, α represents the slope of the pressure decay semilog curve in megapascals per second, mugDenotes the gas viscosity in MPa.s.cgExpressed as gas compressibility in MPa-1，VuAnd VdRespectively representing the volume of the upstream cavity and the volume of the downstream cavity, wherein L represents the height of the core sample and is expressed in centimeters, and A represents the sectional area along the direction vertical to the column axis of the core sample and is expressed in square centimeters.
Step S102: and determining the average pore radius of the core sample under the specified net pressure according to the gas logging permeability, and establishing the correlation between the average pore radius and the net pressure according to the average pore radius of the core sample under the specified net pressure.
In this embodiment, determining the average pore radius of the core sample at the specified net pressure according to the gas permeability may specifically include determining a gas slip factor of the core sample according to the gas permeability of the core sample at the specified net pressure. An average pore radius of the core sample at the specified net pressure may be determined based on the gas slip factor.
In this embodiment, determining the gas slip factor of the core sample under the specified net pressure according to the gas logging permeability of the core sample under the specified net pressure may specifically include determining a plurality of gas logging permeabilities of the core sample under a plurality of specified net pressures, respectively, obtaining a plurality of gas inlet and outlet average pressures corresponding to the plurality of specified net pressures, respectively, and obtaining a plurality of data points by using one gas logging permeability corresponding to the inverse of one gas inlet and outlet average pressure as one data point. A linear fit process may be performed on the plurality of data points to determine a fitted straight line between the gas permeability and the inverse of the average gas inlet and outlet pressure. A gas slip factor for the core sample at the specified net pressure may be determined based on a slope and an intercept in the fitted straight line.
In the present embodiment, the linear fitting process may specifically be a least square normal fitting process.
In this embodiment, the gas slip factor of the core sample may be determined using the following equation:
b＝k∞×a2
k∞＝a1
wherein b represents a gas slip factor, k, of the core sample∞The permeability in grams of the core sample is expressed in millidarcy, a1Representing the slope of said fitted line, a2Represents the intercept of the fitted line.
In this embodiment, the average pore radius of the core sample at the specified net pressure may be determined using the following equation:
wherein r represents the average pore radius of the core sample in microns, c represents a proportionality constant, λ represents the gas molecule mean free path in microns, and P representspThe average pressure of a gas inlet and a gas outlet corresponding to the specified net pressure is expressed in megapascals, b represents a gas slip factor of the rock core sample, mugGas viscosity in MPa.s, RgDenotes the gas constant in joules/(kelvin-mole) T denotes absolute temperature in kelvin, M denotes the molar mass of the gas molecule.
In this embodiment, establishing the correlation between the average pore radius and the net pressure according to the average pore radius of the core sample under the specified net pressure may specifically include determining a plurality of average pore radii of the core sample under a plurality of specified net pressures, respectively, and taking one average pore radius corresponding to one specified net pressure as one data point to obtain a plurality of data points. The plurality of data points may be fit to establish a correlation of the average pore radius to net pressure.
Step S103: and determining a rock core imbibition dimensionless time model of the target oil reservoir based on the correlation between the average pore radius and the net pressure.
In this embodiment, based on the correlation between the average pore radius and the net pressure, the following formula may be used to determine the core imbibition dimensionless time model of the target reservoir:
wherein, tDRepresenting a dimensionless time in the core imbibition dimensionless time model; r (p) represents the average pore radius as a function of net pressure determined from the correlation of average pore radius to net pressure; t represents imbibition time; c represents the fixation coefficient of the core sample, σ represents the interfacial tension between the wetting and non-wetting phases, μwDenotes the viscosity of the wetting phase, μoRepresents the viscosity of the non-wetting phase; l isCRepresenting a characteristic length, V, of the core samplebRepresents the volume of matrix in the core sample, AiDenotes the area of the imbibition contact surface in the i-th imbibition direction,/AiThe distance from the imbibition contact surface to the closed boundary in the i-th imbibition direction at the imbibition front edge is shown, and n represents the number of imbibition directions.
In one embodiment of the application, the method for determining the dimensionless time model of core imbibition can also be provided with an average pore radius, a characteristic length and a fixed coefficient of the target reservoir under a specified formation overburden pressure. Wherein the specified formation overburden pressure is the same as the specified net pressure. The method for determining the dimensionless time model of core imbibition may further include: a soak time of the core sample at the specified net pressure may be determined; the soaking time of the target oil reservoir under the specified formation covering pressure can be determined based on the soaking time of the core sample, a core imbibition dimensionless time model of the target oil reservoir, and an average pore radius, a characteristic length and a fixed coefficient of the target oil reservoir.
In the present embodimentThe core sample can be subjected to a pressurized imbibition experiment under a specified net pressure, and the soaking time of the core sample under the specified net pressure is determined. Specifically, for example, before performing the pressurized imbibition experiment, the core sample in a cylindrical shape may be subjected to oil washing treatment and drying treatment, a small section (e.g., 1-2 cm high) is cut from the end face of the core sample to measure the contact angle, and the remaining section (e.g., 4.6-5.2 cm high) is subjected to vacuum pumping and pressurized saturated oil treatment. Wherein the oil may be kerosene. After the treatment before the experiment is carried out on the core sample, the initial T of the core sample can be tested by using a low-field nuclear magnetic resonance analyzer2A spectral signal. Then, as shown in fig. 2, the core sample after the pre-treatment of the experiment and 100 ml of deuterium aqueous solution of potassium chloride with concentration of 2% are placed in the piston container in fig. 2, the two-way valves at the upstream and downstream of the piston container in fig. 2 are opened, then distilled water is continuously injected into the bottom of the piston container at a constant flow rate of 10 ml/min by the ISCO high-pressure high-precision plunger pump in fig. 2 until the two-way valve at the upstream is discharged, the two-way valve at the upstream is closed, then the ISCO high-pressure high-precision plunger pump is switched to a constant pressure displacement mode to keep the net pressure in the piston container at the designated net pressure, the core sample is taken out at different times, and the T of the core sample at different times after the pressure imbibition experiment is carried out by using the low-field nuclear magnetic resonance analyzer2Spectrum signal, and finally, the T of the rock core sample at different moments after the pressurized imbibition experiment is carried out2Spectral signal, and initial T before experiment2Spectrum signals are respectively converted into the kerosene quality, and the extraction degree of the kerosene in the rock core samples at different moments after the pressurized imbibition experiment is carried out is calculated by adopting the following formula:
wherein R isoilRepresents the degree of extraction of kerosene, m0Represents the mass of saturated kerosene in the core sample before carrying out the imbibition test under pressure, mjShows the core sample measured at the jth moment in the process of carrying out the pressurized imbibition experimentThe mass of kerosene remaining in the process. The imbibition time when the extraction degree of kerosene in the core sample subjected to the under-pressure imbibition experiment under the specified net pressure reaches a stable stage can be used as the soaking time of the core sample under the specified net pressure. Wherein, the air compressor, the pneumatic valve, the three-way valve and the pressure gauge in the pressurized imbibition experimental device in fig. 2 are respectively matched with an ISCO high-pressure high-precision plunger pump (i.e. the ISCO pump in fig. 2) for use.
In this embodiment, the soaking time of the target reservoir at the specified formation pressure may be determined using the following formula:
wherein (t)shut-in)fieldIndicating the soaking time of the target oil reservoir under the specified stratum covering pressure, (t)shut-in)labRepresenting a shut-in time of the core sample at the specified net pressure; cfield、rfieldAnd (L)C)fieldRespectively representing the fixed coefficient, the average pore radius and the characteristic length of the target oil reservoir under the specified formation overburden pressure; clab、rlabAnd (L)C)labRespectively representing the fixed coefficient, average pore radius, and characteristic length of the core sample at the specified net pressure.
In one implementation scenario, the deldos basin huaqing field yuan 284 block extension group length 631 may be selected to develop 9 compact core samples of layer system with a coring depth of 2100m to 2200m, the well section is an delta leading edge-front delta sedimentary deposition environment, and the compact sandstone body is composed of quartz, feldspar, clay minerals and carbonate minerals. After the oil washing treatment and the drying treatment are respectively carried out on the 9 columnar core samples, 4 core samples (core samples A11, A12, A13 and A14) are used for measuring gas permeability by a pulse attenuation method, and 5 core samples (core samples B21, B22, B23, B24 and B25) are used for carrying out a pressure imbibition experiment. Before the under-pressure imbibition experiment, a section of 1-2 cm of part is intercepted from the end face of the rock core for contact angle test, and the rest part (with the height of 4.6-5.2 cm) is treated by saturated oil through a vacuum pressurization saturation device and then taken out for the under-pressure imbibition experiment.
And measuring the gas permeability of 4 compact rock core samples under the specified net pressure of 2.5MPa, 5MPa, 10MPa and 15MPa respectively by a pulse attenuation method, drawing a fitting straight line of the gas permeability and the reciprocal of the average pressure at the fluid inlet and outlet as shown in figure 3, determining a corresponding gas slippage factor according to the slope and intercept of the fitting straight line, and calculating the corresponding average pore radius. Wherein, the abscissa and ordinate in FIG. 3 are respectively the reciprocal of the average pressure at the fluid inlet and outlet and the gas permeability in MPa-1And millidarcy. In FIG. 3, (a), (b), (c), and (d) are the gas permeability as a function of the reciprocal of the average pressure at the fluid inlet and outlet for core sample A11 at specified net pressures of 2.5MPa, 5MPa, 10MPa, and 15MPa, respectively. The average pore radius is plotted as a function of the specified net pressure as shown in fig. 4, where the abscissa and ordinate in fig. 4 are the specified net pressure and average pore radius, respectively, in mpa and micron, respectively. And (3) fitting by adopting origin software to obtain a function relation of the average pore radius along with the change of the net pressure:
r(p)＝0.835·exp(-p/2.711)+0.0792
and obtaining a function relation of the average pore radius along with the change of the net pressure according to fitting, and establishing a rock core imbibition dimensionless time model of the target oil reservoir. Through an under-pressure imbibition experiment, a change curve of kerosene production degree of 5 compact core samples along with imbibition time under the specified net pressures of 0, 2.5MPa, 5MPa, 10MPa and 15MPa respectively as shown in figure 5 can be obtained, so that well closing time of core scales under the specified net pressures of 0, 2.5MPa, 5MPa, 10MPa and 15MPa respectively can be determined, and the well closing time of the target oil reservoir under the specified stratum covering pressure is determined by adopting the following formula:
wherein (t)shut-in)fieldIndicating the soaking time of the target oil reservoir under the specified stratum covering pressure, (t)shut-in)labRepresenting a shut-in time of the core sample at the specified net pressure; cfield、rfieldAnd (L)C)fieldRespectively representing the fixed coefficient, the average pore radius and the characteristic length of the target oil reservoir under the specified formation overburden pressure; clab、rlabAnd (L)C)labRespectively representing the fixed coefficient, average pore radius, and characteristic length of the core sample at the specified net pressure. In fig. 5, the abscissa and ordinate represent imbibition time and extraction degree, respectively, in days and percentages (%).
According to the embodiment of the method for determining the core imbibition dimensionless time model, the influence of formation overburden pressure is considered to determine the gas logging permeability of the core sample under the specified net pressure, the average pore radius of the core sample under the specified net pressure can be determined according to the gas logging permeability, and the incidence relation between the average pore radius and the net pressure can be established according to the average pore radius of the core sample under the specified net pressure; and finally, determining the core imbibition dimensionless time model of the target oil reservoir based on the correlation between the average pore radius and the net pressure, so that the core imbibition dimensionless time model is established under the net pressure same as the formation overburden pressure, thus the accuracy of the established core imbibition dimensionless time model can be improved, and the core scale result can be more accurately applied to the oil reservoir scale.
FIG. 6 is a schematic diagram illustrating the components of an embodiment of the apparatus for determining a dimensionless time model of core imbibition. The device for determining the core imbibition dimensionless time model provides target parameter information obtained when a core sample of a target oil reservoir is subjected to gas logging permeability test under specified net pressure. As shown in fig. 6, the apparatus for determining a dimensionless time model of core imbibition may include: gas permeability determination module 100, association establishment module 200, and dimensionless time model determination module 300.
The gas permeability determination module 100 may be configured to determine a gas permeability of the core sample at the specified net pressure according to the target parameter information.
The correlation establishing module 200 may be configured to determine an average pore radius of the core sample under the specified net pressure according to the gas logging permeability, and establish a correlation between the average pore radius and the net pressure according to the average pore radius of the core sample under the specified net pressure.
The dimensionless time model determining module 300 may be configured to determine a core imbibition dimensionless time model of the target reservoir based on a correlation between the average pore radius and the net pressure.
Fig. 7 is a schematic structural diagram illustrating a composition of another embodiment of the apparatus for determining a dimensionless time model of core imbibition according to the present application. As shown in fig. 7, the apparatus for determining a dimensionless time model of core imbibition may include a memory, a processor, and a computer program stored in the memory, where the memory stores target parameter information obtained when a gas permeability test is performed on a core sample of a reservoir of interest at a specified net pressure, and the computer program is executed by the processor to perform the following steps:
step S101: determining the gas logging permeability of the core sample under the specified net pressure according to the target parameter information;
step S102: determining the average pore radius of the core sample under the specified net pressure according to the gas logging permeability, and establishing the correlation between the average pore radius and the net pressure according to the average pore radius of the core sample under the specified net pressure;
step S103: and determining a rock core imbibition dimensionless time model of the target oil reservoir based on the correlation between the average pore radius and the net pressure.
The device embodiment for determining the rock core imbibition dimensionless time model corresponds to the method embodiment for determining the rock core imbibition dimensionless time model, the technical scheme of the method embodiment for determining the rock core imbibition dimensionless time model can be realized, and the technical effects of the method embodiment can be obtained.
In the 90 s of the 20 th century, improvements in a technology could clearly distinguish between improvements in hardware (e.g., improvements in circuit structures such as diodes, transistors, switches, etc.) and improvements in software (improvements in process flow). However, as technology advances, many of today's process flow improvements have been seen as direct improvements in hardware circuit architecture. Designers almost always obtain the corresponding hardware circuit structure by programming an improved method flow into the hardware circuit. Thus, it cannot be said that an improvement in the process flow cannot be realized by hardware physical modules. For example, a Programmable Logic Device (PLD), such as a Field Programmable Gate Array (FPGA), is an integrated circuit whose Logic functions are determined by programming the Device by a user. A digital system is "integrated" on a PLD by the designer's own programming without requiring the chip manufacturer to design and fabricate application-specific integrated circuit chips. Furthermore, nowadays, instead of manually making an integrated Circuit chip, such Programming is often implemented by "logic compiler" software, which is similar to a software compiler used in program development and writing, but the original code before compiling is also written by a specific Programming Language, which is called Hardware Description Language (HDL), and HDL is not only one but many, such as abel (advanced Boolean Expression Language), ahdl (alternate Language Description Language), traffic, pl (core unified Programming Language), HDCal, JHDL (Java Hardware Description Language), langue, Lola, HDL, laspam, hardsradware (Hardware Description Language), vhjhd (Hardware Description Language), and vhigh-Language, which are currently used in most popular applications. It will also be apparent to those skilled in the art that hardware circuitry that implements the logical method flows can be readily obtained by merely slightly programming the method flows into an integrated circuit using the hardware description languages described above.
Those skilled in the art will also appreciate that, in addition to implementing the controller as pure computer readable program code, the same functionality can be implemented by logically programming method steps such that the controller is in the form of logic gates, switches, application specific integrated circuits, programmable logic controllers, embedded microcontrollers and the like. Such a controller may thus be considered a hardware component, and the means included therein for performing the various functions may also be considered as a structure within the hardware component. Or even means for performing the functions may be regarded as being both a software module for performing the method and a structure within a hardware component.
The apparatuses and modules illustrated in the above embodiments may be implemented by a computer chip or an entity, or by a product with certain functions.
For convenience of description, the above devices are described as being divided into various modules by functions, and are described separately. Of course, the functionality of the various modules may be implemented in the same one or more software and/or hardware implementations as the present application.
From the above description of the embodiments, it is clear to those skilled in the art that the present application can be implemented by software plus necessary general hardware platform. With this understanding in mind, the present solution, or portions thereof that contribute to the prior art, may be embodied in the form of a software product, which in a typical configuration includes one or more processors (CPUs), input/output interfaces, network interfaces, and memory. The computer software product may include instructions for causing a computing device (which may be a personal computer, a server, or a network device, etc.) to perform the methods described in the various embodiments or portions of embodiments of the present application. The computer software product may be stored in a memory, which may include forms of volatile memory in a computer readable medium, Random Access Memory (RAM) and/or non-volatile memory, such as Read Only Memory (ROM) or flash memory (flash RAM). Memory is an example of a computer-readable medium. Computer-readable media, including both non-transitory and non-transitory, removable and non-removable media, may implement information storage by any method or technology. The information may be computer readable instructions, data structures, modules of a program, or other data. Examples of computer storage media include, but are not limited to, phase change memory (PRAM), Static Random Access Memory (SRAM), Dynamic Random Access Memory (DRAM), other types of Random Access Memory (RAM), Read Only Memory (ROM), Electrically Erasable Programmable Read Only Memory (EEPROM), flash memory or other memory technology, compact disc read only memory (CD-ROM), Digital Versatile Discs (DVD) or other optical storage, magnetic cassettes, magnetic tape magnetic disk storage or other magnetic storage devices, or any other non-transmission medium that can be used to store information that can be accessed by a computing device. As defined herein, computer readable media does not include transitory computer readable media (transient media), such as modulated data signals and carrier waves.
The embodiments in the present specification are described in a progressive manner, and the same and similar parts among the embodiments are referred to each other, and each embodiment focuses on the differences from the other embodiments. In particular, as for the apparatus embodiment, since it is substantially similar to the method embodiment, the description is relatively simple, and for the relevant points, reference may be made to the partial description of the method embodiment.
The application is operational with numerous general purpose or special purpose computing system environments or configurations. For example: personal computers, server computers, hand-held or portable devices, tablet-type devices, multiprocessor systems, microprocessor-based systems, set top boxes, programmable consumer electronics, network PCs, minicomputers, mainframe computers, distributed computing environments that include any of the above systems or devices, and the like.
The application may be described in the general context of computer-executable instructions, such as program modules, being executed by a computer. Generally, program modules include routines, programs, objects, components, data structures, etc. that perform particular tasks or implement particular abstract data types. The application may also be practiced in distributed computing environments where tasks are performed by remote processing devices that are linked through a communications network. In a distributed computing environment, program modules may be located in both local and remote computer storage media including memory storage devices.
While the present application has been described with examples, those of ordinary skill in the art will appreciate that there are numerous variations and permutations of the present application without departing from the spirit of the application, and it is intended that the appended claims encompass such variations and permutations without departing from the spirit of the application.
Claims (13)
1. A method for determining a core imbibition dimensionless time model is characterized in that target parameter information is provided after a core sample of a target oil reservoir is subjected to a gas logging permeability test under specified net pressure; the method comprises the following steps:
determining the gas logging permeability of the core sample under the specified net pressure according to the target parameter information;
determining the average pore radius of the core sample under the specified net pressure according to the gas logging permeability, and establishing the correlation between the average pore radius and the net pressure according to the average pore radius of the core sample under the specified net pressure;
and determining a rock core imbibition dimensionless time model of the target oil reservoir based on the correlation between the average pore radius and the net pressure.
2. The method as claimed in claim 1, wherein the gas permeability of the core sample at the specified net pressure is determined from a slope of a pressure decay semi-logarithmic curve, an upstream cavity volume, and a downstream cavity volume in the target parameter information; wherein the pressure decay semi-logarithmic curve slope, the upstream cavity volume, and the downstream cavity volume are associated with the specified net pressure.
3. The method as recited in claim 2, wherein the core sample is cylindrical in shape, and the gas permeability of the core sample at the specified net pressure is determined using the following equation:
wherein k isaThe gas permeability of the core sample is expressed in millidarcy, α represents the slope of the pressure decay semilog curve in megapascals per second, mugDenotes the gas viscosity in MPa.s.cgExpressed as gas compressibility in MPa-1，VuAnd VdRespectively representing the volume of the upstream cavity and the volume of the downstream cavity, wherein L represents the height of the core sample and is expressed in centimeters, and A represents the sectional area along the direction vertical to the column axis of the core sample and is expressed in square centimeters.
4. The method as recited in claim 1, wherein determining an average pore radius of the core sample at the specified net pressure comprises:
determining a gas slippage factor of the core sample according to the gas logging permeability;
determining an average pore radius of the core sample at the specified net pressure based on the gas slip factor.
5. The method as recited in claim 4, wherein determining a gas slip factor for the core sample at the specified net pressure comprises:
respectively determining a plurality of gas logging permeabilities of the core sample under a plurality of specified net pressures, obtaining a plurality of gas inlet and outlet average pressures corresponding to the specified net pressures, and taking one gas logging permeability corresponding to the inverse of one gas inlet and outlet average pressure as a data point to obtain a plurality of data points;
performing linear fitting processing on the plurality of data points to determine a fitted straight line between the gas permeability and the inverse of the average pressure at the gas inlet and outlet;
and determining a gas slip factor of the core sample at the specified net pressure according to the slope and the intercept in the fitted straight line.
6. The method as recited in claim 5, wherein the gas slip factor of the core sample is determined using the following equation:
b＝k∞×a2
k∞＝a1
wherein b represents a gas slip factor, k, of the core sample∞The permeability in grams of the core sample is expressed in millidarcy, a1Representing the slope of said fitted line, a2Represents the intercept of the fitted line.
7. The method as recited in claim 4, wherein an average pore radius of the core sample at the specified net pressure is determined using the following equation:
wherein r represents the average pore radius of the core sample in microns, c represents a proportionality constant, λ represents the gas molecule mean free path in microns, and P representspThe average pressure of a gas inlet and a gas outlet corresponding to the specified net pressure is expressed in megapascals, b represents a gas slip factor of the rock core sample, mugRepresenting the viscosity of the gas in MPa.s, RgDenotes the gas constant in joules/(kelvin-mol), T denotes the absolute temperature in kelvin, and M denotes the molar mass of the gas molecule.
8. The method of claim 1, wherein correlating the average pore radius to a net pressure comprises:
respectively determining a plurality of average pore radii of the rock core sample under a plurality of specified net pressures, and taking one average pore radius corresponding to one specified net pressure as a data point to obtain a plurality of data points;
and fitting the plurality of data points to establish the correlation between the average pore radius and the net pressure.
9. The method according to claim 1, wherein the core imbibition dimensionless time model of the reservoir of interest is determined using the following formula:
wherein, tDRepresenting a dimensionless time in the core imbibition dimensionless time model; r (p) represents the average pore radius as a function of net pressure determined from the correlation of average pore radius to net pressure; t represents imbibition time; c represents the fixation coefficient of the core sample, σ represents the interfacial tension between the wetting and non-wetting phases, μwDenotes the viscosity of the wetting phase, μoRepresents the viscosity of the non-wetting phase; l isCRepresenting a characteristic length, V, of the core samplebRepresents the volume of matrix in the core sample, AiIndicates the area of the imbibition contact surface in the ith imbibition direction,
indicating the penetration in the ith penetration direction at the penetration front edgeThe distance from the suction contact surface to the closed boundary, n, indicates the number of directions of imbibition.
10. The method of claim 1, further providing an average pore radius, a characteristic length, and a fixed coefficient for the reservoir of interest at a given formation pressure; wherein the specified formation overburden pressure is the same as the specified net pressure; the method further comprises the following steps:
determining a soak time of the core sample at the specified net pressure;
and determining the soaking time of the target oil reservoir under the specified stratum pressure based on the soaking time of the core sample, a core imbibition dimensionless time model of the target oil reservoir, and the average pore radius, the characteristic length and the fixed coefficient of the target oil reservoir.
11. The method of claim 10, wherein the soak time for the reservoir of interest at the specified formation pressure is determined using the following equation:
wherein (t)shut-in)fieldIndicating the soaking time of the target oil reservoir under the specified stratum covering pressure, (t)shut-in)labRepresenting a shut-in time of the core sample at the specified net pressure; cfield、rfieldAnd (L)C)fieldRespectively representing the fixed coefficient, the average pore radius and the characteristic length of the target oil reservoir under the specified formation overburden pressure; clab、rlabAnd (L)C)labRespectively representing the fixed coefficient, average pore radius, and characteristic length of the core sample at the specified net pressure.
12. A device for determining a rock core imbibition dimensionless time model is characterized in that the device provides target parameter information obtained when a rock core sample of a target oil reservoir is subjected to gas logging permeability test under specified net pressure; the device comprises: the system comprises a gas permeability determining module, an incidence relation establishing module and a dimensionless time model determining module; wherein,
the gas permeability determining module is used for determining the gas logging permeability of the rock core sample under the specified net pressure according to the target parameter information;
the incidence relation establishing module is used for determining the average pore radius of the rock core sample under the specified net pressure according to the gas logging permeability, and establishing the incidence relation between the average pore radius and the net pressure according to the average pore radius of the rock core sample under the specified net pressure;
and the dimensionless time model determining module is used for determining a rock core imbibition dimensionless time model of the target oil reservoir based on the incidence relation between the average pore radius and the net pressure.
13. An apparatus for determining a dimensionless time model of core imbibition, comprising a memory, a processor, and a computer program stored on the memory, wherein the memory stores target parameter information obtained when a gas permeability test is performed on a core sample of a target reservoir at a specified net pressure, and the computer program is executed by the processor to perform the steps of:
determining the gas logging permeability of the core sample under the specified net pressure according to the target parameter information;
determining the average pore radius of the core sample under the specified net pressure according to the gas logging permeability, and establishing the correlation between the average pore radius and the net pressure according to the average pore radius of the core sample under the specified net pressure;
and determining a rock core imbibition dimensionless time model of the target oil reservoir based on the correlation between the average pore radius and the net pressure.
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