CN113155694A - Reservoir flow porosity determination method based on constant-pressure mercury-pressing experiment - Google Patents
Reservoir flow porosity determination method based on constant-pressure mercury-pressing experiment Download PDFInfo
- Publication number
- CN113155694A CN113155694A CN202011464123.2A CN202011464123A CN113155694A CN 113155694 A CN113155694 A CN 113155694A CN 202011464123 A CN202011464123 A CN 202011464123A CN 113155694 A CN113155694 A CN 113155694A
- Authority
- CN
- China
- Prior art keywords
- reservoir
- mercury
- pressure
- porosity
- constant
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Pending
Links
- 238000003825 pressing Methods 0.000 title claims abstract description 25
- 238000000034 method Methods 0.000 title claims abstract description 19
- 238000002474 experimental method Methods 0.000 title description 8
- 229910052753 mercury Inorganic materials 0.000 claims abstract description 67
- QSHDDOUJBYECFT-UHFFFAOYSA-N mercury Chemical compound [Hg] QSHDDOUJBYECFT-UHFFFAOYSA-N 0.000 claims abstract description 64
- 238000004519 manufacturing process Methods 0.000 claims abstract description 47
- 238000012360 testing method Methods 0.000 claims abstract description 27
- 238000009533 lab test Methods 0.000 claims abstract description 8
- 238000005070 sampling Methods 0.000 claims abstract description 7
- 239000003129 oil well Substances 0.000 claims abstract description 4
- 239000011148 porous material Substances 0.000 claims description 16
- 239000011435 rock Substances 0.000 claims description 16
- 238000006243 chemical reaction Methods 0.000 claims description 8
- 238000009736 wetting Methods 0.000 claims description 7
- 230000015572 biosynthetic process Effects 0.000 claims description 6
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 4
- 239000012530 fluid Substances 0.000 description 11
- 238000004891 communication Methods 0.000 description 3
- 238000011161 development Methods 0.000 description 3
- 230000035699 permeability Effects 0.000 description 2
- 238000009826 distribution Methods 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 230000002349 favourable effect Effects 0.000 description 1
- 230000005484 gravity Effects 0.000 description 1
- 238000004445 quantitative analysis Methods 0.000 description 1
- 238000011160 research Methods 0.000 description 1
- 238000004062 sedimentation Methods 0.000 description 1
- 239000007787 solid Substances 0.000 description 1
- 238000006467 substitution reaction Methods 0.000 description 1
Images
Classifications
-
- 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
Landscapes
- Chemical & Material Sciences (AREA)
- Physics & Mathematics (AREA)
- Analytical Chemistry (AREA)
- Dispersion Chemistry (AREA)
- Health & Medical Sciences (AREA)
- Life Sciences & Earth Sciences (AREA)
- Fluid Mechanics (AREA)
- Biochemistry (AREA)
- General Health & Medical Sciences (AREA)
- General Physics & Mathematics (AREA)
- Immunology (AREA)
- Pathology (AREA)
- Physical Or Chemical Processes And Apparatus (AREA)
Abstract
The invention provides a reservoir flow porosity determination method based on a constant-pressure mercury intrusion test, which comprises the following steps of: s001: sampling a plurality of oil wells of an oil field and determining the interconnected porosity of the reservoir samples producing oil; s002: performing a constant-pressure mercury-pressing test on the reservoir sample, drawing a constant-pressure mercury-pressing curve, and determining the maximum mercury-feeding saturation of the reservoir sample according to the constant-pressure mercury-pressing curve; s003: calculating the effective porosity of the reservoir sample according to the connected porosity and the maximum mercury inlet saturation of the reservoir sample; s004: converting the oil layer production pressure difference into laboratory test pressure, namely mercury inlet pressure, and determining the mercury inlet saturation corresponding to the oil layer production pressure difference according to a constant-pressure mercury pressing curve; s005: and converting the reservoir flowing porosity by using the mercury inlet saturation corresponding to the effective porosity of the reservoir sample and the oil layer production pressure difference and the maximum mercury inlet saturation of the reservoir sample.
Description
Technical Field
The invention belongs to the technical field of oil and gas field production, and particularly relates to a reservoir flow porosity determination method based on a constant-pressure mercury-pressing experiment.
Background
A reservoir is a rock formation that is capable of storing and percolating fluids, the basic properties of which are porosity and permeability. The porosity and permeability of the reservoir depends on the porosity. The voids are spaces in the rock that are not filled with solid matter and can be subdivided into larger scale pores and throats with narrow communication between the larger pores. The pores determine the capacity of the reservoir to store fluid, while the throat controls the capacity of the reservoir to percolate fluid, which combine organically to form a reservoir space to contain and percolate fluid. Therefore, the porous medium reservoir space can be regarded as a three-dimensional pore-throat network consisting of pores and throats, and the flow of fluid in the porous medium reservoir space is endowed with a seepage rule. Most pores in a reservoir can always find other pores in coordinated communication with it, however, there are also a few unconnected (or dead) pores. Flow porosity refers to the ratio of the volume of flow pores in the rock to the total volume of the rock, expressed as a percentage, at a certain pressure differential. The determination of the reservoir flow porosity is of great significance and mainly shows 3 aspects: 1. reservoir flow porosity is a function of differential production pressure. Along with the change of production pressure difference in the oil field development process, the pore-throat network space which can be started and participate in seepage in the reservoir is also changed, namely the flow porosity of the reservoir is changed. Thus, reservoir flow porosity is a function of differential production pressure. 2. The relative size of the reservoir flow porosity is an important measure of the degree of reservoir fluid mobilization. The reservoir communicated porosity is greater than or equal to the effective porosity and greater than or equal to the flow porosity, so the reservoir communicated porosity is greater than or equal to the effective porosity and greater than or equal to the flow porosity. The ratio of the reservoir flowing porosity to the communicating porosity can visually reflect the fluid utilization degree in the communicating pores of the reservoir; the ratio of the flowing porosity of the reservoir to the effective porosity can visually reflect the flowing degree of the fluid in the effective pores of the reservoir; therefore, the relative size of the reservoir flow porosity is an important measure of the extent of reservoir fluid mobilization. 3. Reservoir flow porosity can be used as a basis for production pressure differential adjustment. When the product of the reservoir flowing porosity and the reservoir communicating porosity is equal to the original oil saturation, oil and gas in the reservoir participate in seepage, and the oil and gas utilization effect is the best, so that the production pressure difference corresponding to the flowing porosity is the reasonable production pressure difference. Therefore, the reservoir flow porosity can be used as a basis for the production pressure difference adjustment.
At present, the concept of reservoir flow porosity is clear, but a calculation example is rarely seen, because the reservoir flow porosity is a function of production pressure difference, but the relationship between the reservoir flow porosity and the production pressure difference is lack of an exact physical quantitative method report, so that the research and the application of the reservoir flow porosity at present are not deep enough, and the real-time grasping of the micro-exploitation condition of reservoir fluid and the targeted production adjustment in the oilfield development process are not facilitated.
Disclosure of Invention
The present invention provides a reservoir flow porosity determination method based on a constant pressure mercury intrusion test, which overcomes the above problems or at least partially solves or alleviates the above problems.
Therefore, the invention provides a reservoir flow porosity determination method based on a constant-pressure mercury intrusion test, which is characterized by comprising the following steps of:
s001: sampling a plurality of wells of an oilfield and determining the interconnected porosity of a reservoir sample producing oil
S002: performing a constant-pressure mercury-pressing test on the reservoir sample, drawing a constant-pressure mercury-pressing curve, and determining the maximum mercury-feeding saturation S of the reservoir sample according to the constant-pressure mercury-pressing curveHg-max；
S003: connected porosity according to reservoir sample
And maximum mercury ingress saturation SHg-maxCalculating effective porosity of reservoir sample
S004: pressure difference delta p of oil layer productionRConversion into laboratory test pressure, i.e. mercury inlet pressure Δ pLDetermining the mercury inlet saturation S corresponding to the production pressure difference of the oil layer according to the constant-pressure mercury-pressing curveHg-f(ΔpR)；
S005: using effective porosity of reservoir sample
Mercury inlet saturation S corresponding to oil layer production pressure differenceHg-f(ΔpR) And maximum mercury ingress saturation S of the reservoir sampleHg-maxConversion of reservoir flow porosity
In step S001, the sampling depth is within the range of the main oil production or the gas production depth of the oil well.
In step S002, 29 test pressure points are selected from a single reservoir sample, and the mercury inlet pressure, pore throat radius and mercury inlet saturation are respectively measured at each test pressure point, and a constant pressure mercury curve is drawn based on the test pressure points
In step S003, the interconnected porosity of the reservoir sample is used
Multiplied by its maximum mercury-in saturation SHg-maxObtaining effective porosity of reservoir sample
Namely, it is
In step S004, the laboratory tests the pressure, i.e. the mercury inlet pressure
Wherein σLIs the laboratory air-mercury interfacial tension, θLIs the wetting angle of laboratory rock, Δ pRFor production of pressure difference, sigma, of reservoirRIs the formation oil-water interfacial tension, θRIs the formation rock wetting angle.
In step S005, reservoir flow porosity corresponding to the reservoir production pressure difference Δ p
Wherein S isHg-maxMaximum reservoir mercury saturation, SHg-f(Δ p) is the effective porosity of the reservoir sample
And the mercury feeding saturation corresponding to the oil layer production pressure difference delta p.
The reservoir flow porosity determining method based on the constant-pressure mercury intrusion experiment can determine the reservoir flow porosity of the reservoir of the oil field under different production pressure differences, can be used as a basis for determining and adjusting the reasonable production pressure difference of the oil field, is favorable for real-time grasping of the microcosmic exploitation condition of the reservoir fluid and targeted production adjustment in the oil field development process, and has important significance for high-efficiency exploitation of the oil field.
Drawings
FIG. 1 is a flow chart of the present invention;
fig. 2 is a graph of constant pressure mercury intrusion of the # 1 rock sample in step S002 according to the embodiment of the present invention.
Detailed Description
The invention is further illustrated by the following specific examples.
Example 1
A reservoir flow porosity determination method based on a constant-pressure mercury intrusion test comprises the following steps:
s001: for 6 oil fields3Multiple wells of oil are sampled and the interconnected porosity of the reservoir samples of oil production is determined
S002: performing a constant-pressure mercury-pressing test on the reservoir sample, drawing a constant-pressure mercury-pressing curve, and determining the maximum mercury-feeding saturation S of the reservoir sample according to the constant-pressure mercury-pressing curveHg-max；
S003: connected porosity according to reservoir sample
And maximum mercury ingress saturation SHg-maxCalculating effective porosity of reservoir sample
S004: pressure difference delta p of oil layer productionRConversion into laboratory test pressure, i.e. mercury inlet pressure Δ pLDetermining the mercury inlet saturation S corresponding to the production pressure difference of the oil layer according to the constant-pressure mercury-pressing curveHg-f(ΔpR)；
S005: using effective porosity of reservoir sample
Mercury inlet saturation S corresponding to oil layer production pressure differenceHg-f(ΔpR) And maximum mercury ingress saturation S of the reservoir sampleHg-maxConversion of reservoir flow porosity
Example 2
The target layer of the oil field is a three-layer system upper system extension group length 63Oil group, belonging to deep lake-semi-deep lake phase gravity flow sedimentation. The oil field is composed of lithologic oil deposit, has no uniform oil-water interface and pressure system, and has the characteristics of large oil-bearing area and large reserve capacity scale. To determine the field length of south joist 63Oil reservoir flow porosity, as shown in fig. 1, a reservoir flow porosity determination method based on a constant pressure mercury intrusion test adopts the following steps:
s001: for 6 oil fields3Multiple wells of oil are sampled and the interconnected porosity of the reservoir samples of oil production is determined
In step S001, the sampling depth is within the range of the main oil production or the gas production depth of the oil well.
For length 63For oil, the sampling depth of the reservoir ranges from 1900-2100m in depth to 6 in length3The reservoir of the oil was sampled and reservoir connected porosity was obtained by conventional gas logging as shown in table 1. For convenience of discussion, the following description will be given by taking the determination of the porosity of the reservoir microcapillary of the # 1 rock sample, wherein the # 1 rock sample is taken from a mountain 156 well with a well depth of 2060.1m, and the reservoir communication porosity obtained by a conventional laboratory gas logging method is 14.53%.
TABLE 1 CONSTANT PRESSURE MERCURY-PRESSING ROCK SAMPLE CHARACTERISTICS TABLE
S002: performing a constant-pressure mercury-pressing test on the reservoir sample, drawing a constant-pressure mercury-pressing curve, and determining the maximum mercury-feeding saturation S of the reservoir sample according to the constant-pressure mercury-pressing curveHg-max。
In step S002, 29 test pressure points are selected from a single reservoir sample, and the mercury inlet pressure, pore throat radius, and mercury inlet saturation are respectively measured at each test pressure point, and a constant pressure mercury curve is drawn based on the test pressure points.
Developing a constant-pressure mercury intrusion experiment, obtaining the data of the constant-pressure mercury intrusion experiment, wherein the data of the experiment are shown in table 2, drawing a constant-pressure mercury intrusion curve according to mercury intrusion saturation under different mercury intrusion test pressures, as shown in fig. 2, determining the corresponding relation between rock sample pore throat distribution and test pressure, and laying an experiment foundation for determining reservoir flowing porosity. When the constant-pressure mercury-pressing curve reaches the maximum mercury-entering saturation, the pressure-added mercury-entering saturation is continuously increased and is always kept unchanged, the initial point at which the maximum mercury-entering saturation is kept unchanged can be regarded as a boundary point between a capillary pore and a microcapillary pore, and according to the characteristic, the maximum mercury-entering saturation of the read sample is 92.1362%.
TABLE 21 rock specimen constant pressure mercury test data sheet
S003: connected porosity according to reservoir sample
And maximum mercury ingress saturation SHg-maxCalculating effective porosity of reservoir sample
In step S003, the interconnected porosity of the reservoir sample is used
Multiplied by its maximum mercury-in saturation SHg-maxObtaining effective porosity of reservoir sample
Namely, it is
Let the reservoir communicate a porosity of
Maximum mercury ingress saturation of SHg-max92.1362% with an effective porosity of
S004: pressure difference delta p of oil layer productionRConversion into laboratory test pressure, i.e. mercury inlet pressure Δ pLDetermining the mercury inlet saturation S corresponding to the production pressure difference of the oil layer according to the constant-pressure mercury-pressing curveHg-f(ΔpR)。
In step S004, the well reservoir production pressure difference Δ p of the known mountain 156R3MPa, according to Table 2 and Young-Laplace equation
Wherein the laboratory air-mercury interfacial tension σ is shown in Table 3LLaboratory rock wetting angle thetaLFormation oil-water interfacial tension sigmaRAnd formation rock wetting angle thetaRAre all known values.
TABLE 3 wetting Angle and interfacial tension in different systems
Substituting the data in Table 3 into a formula to obtain the laboratory test pressure of the rock sample
On the basis, the mercury inlet saturation S corresponding to the production pressure difference of the oil layer with the pressure of 3MPa is determined by the constant-pressure mercury-pressing curve in figure 2Hg-f(3MPa)＝90.4533％。
S005: using effective porosity of reservoir sample
Mercury inlet saturation S corresponding to oil layer production pressure differenceHg-f(ΔpR) And maximum mercury ingress saturation S of the reservoir sampleHg-maxConversion of reservoir flow porosity
In step S005, the maximum mercury inlet saturation S in the reservoirHg-maxEffective porosity of
Mercury inlet saturation S corresponding to oil layer production pressure differenceHg-f(ΔpR) After the determination, the reservoir flow porosity corresponding to the production pressure difference of the oil layer with the pressure of 3MPa
Can be composed of
And (4) determining the formula.
Namely, it is
The above description is only for the preferred embodiment of the present invention, but the scope of the present invention is not limited thereto, and any changes or substitutions that can be easily conceived by those skilled in the art within the technical scope of the present invention are included in the scope of the present invention. Therefore, the protection scope of the present invention shall be subject to the protection scope of the claims. The components and structures of the present embodiments that are not described in detail are well known in the art and do not constitute essential structural elements or elements.
Claims (6)
1. A reservoir flow porosity determination method based on a constant-pressure mercury intrusion test is characterized by comprising the following steps:
s001: sampling a plurality of wells of an oilfield and determining the interconnected porosity of a reservoir sample producing oil
S002: performing a constant-pressure mercury-pressing test on the reservoir sample, drawing a constant-pressure mercury-pressing curve, and determining the maximum mercury-feeding saturation S of the reservoir sample according to the constant-pressure mercury-pressing curveHg-max；
S003: connected porosity according to reservoir sample
And maximum mercury ingress saturation SHg-maxCalculating effective porosity of reservoir sample
S004: pressure difference delta p of oil layer productionRConversion into laboratory test pressure, i.e. mercury inlet pressure Δ pLDetermining the mercury inlet saturation S corresponding to the production pressure difference of the oil layer according to the constant-pressure mercury-pressing curveHg-f(ΔpR)；
S005: using effective porosity of reservoir sample
Mercury inlet saturation S corresponding to oil layer production pressure differenceHg-f(ΔpR) And maximum mercury ingress saturation S of the reservoir sampleHg-maxConversion of reservoir flow porosity
2. The method for determining reservoir flow porosity based on mercury intrusion test with constant pressure according to claim 1, wherein in step S001, the sampling depth is within the range of oil production or gas production depth of the oil well.
3. The method for determining reservoir flow porosity based on constant-pressure mercury intrusion test according to claim 1, wherein in step S002, 29 test pressure points are selected from a single reservoir sample, and the mercury intrusion pressure, pore throat radius and mercury intrusion saturation are respectively tested at each test pressure point, so as to draw a constant-pressure mercury intrusion curve.
4. The method for determining reservoir flow porosity based on mercury intrusion test with constant pressure as claimed in claim 1, wherein in step S003, the interconnected porosity of the reservoir sample is used
Multiplied by its maximum mercury-in saturation SHg-maxObtaining effective porosity of reservoir sample
Namely, it is
5. The reservoir flow porosity determination method based on constant-pressure mercury intrusion test according to claim 1, wherein in step S004, a laboratory test pressure, namely a mercury intrusion pressure
Wherein σLIs the laboratory air-mercury interfacial tension, θLIs the wetting angle of laboratory rock, Δ pRFor production of pressure difference, sigma, of reservoirRIs the formation oil-water interfacial tension, θRIs the formation rock wetting angle.
6. The method for determining the mobile porosity of the reservoir based on the mercury intrusion test with constant pressure as claimed in claim 1, wherein in step S005, the mobile porosity of the reservoir corresponding to the pressure difference Δ p of the reservoir production
Wherein S isHg-maxMaximum reservoir mercury saturation, SHg-f(Δ p) is the effective porosity of the reservoir sample
And the mercury feeding saturation corresponding to the oil layer production pressure difference delta p.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN202011464123.2A CN113155694A (en) | 2020-12-11 | 2020-12-11 | Reservoir flow porosity determination method based on constant-pressure mercury-pressing experiment |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN202011464123.2A CN113155694A (en) | 2020-12-11 | 2020-12-11 | Reservoir flow porosity determination method based on constant-pressure mercury-pressing experiment |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CN113155694A true CN113155694A (en) | 2021-07-23 |
Family
ID=76882563
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CN202011464123.2A Pending CN113155694A (en) | 2020-12-11 | 2020-12-11 | Reservoir flow porosity determination method based on constant-pressure mercury-pressing experiment |
Country Status (1)
| Country | Link |
|---|---|
| CN (1) | CN113155694A (en) |
Citations (6)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN104458525A (en) * | 2013-09-13 | 2015-03-25 | 中国石油天然气股份有限公司 | Collection and processing method for characterizing micropore throat characteristics by conventional mercury injection curve |
| CN105241798A (en) * | 2015-09-23 | 2016-01-13 | 中国海洋石油总公司 | Quantification characterization method of complex carbonate reservoir permeability |
| CN108956422A (en) * | 2018-07-18 | 2018-12-07 | 中国石油大学(华东) | A kind of porosity experimental measurement method of compact reservoir |
| CN111208053A (en) * | 2020-03-20 | 2020-05-29 | 中国石油大学(北京) | Reservoir micro-capillary porosity determination method based on constant-pressure mercury-pressing experiment |
| US20200249216A1 (en) * | 2019-02-01 | 2020-08-06 | Petrochina Company Limited | Method for Determining Gas Saturation of Tight Reservoir |
| CN111521539A (en) * | 2020-05-14 | 2020-08-11 | 中国地质大学（武汉） | Quantitative characterization method for different types of pore structures in compact conglomerate reservoir |
-
2020
- 2020-12-11 CN CN202011464123.2A patent/CN113155694A/en active Pending
Patent Citations (6)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN104458525A (en) * | 2013-09-13 | 2015-03-25 | 中国石油天然气股份有限公司 | Collection and processing method for characterizing micropore throat characteristics by conventional mercury injection curve |
| CN105241798A (en) * | 2015-09-23 | 2016-01-13 | 中国海洋石油总公司 | Quantification characterization method of complex carbonate reservoir permeability |
| CN108956422A (en) * | 2018-07-18 | 2018-12-07 | 中国石油大学(华东) | A kind of porosity experimental measurement method of compact reservoir |
| US20200249216A1 (en) * | 2019-02-01 | 2020-08-06 | Petrochina Company Limited | Method for Determining Gas Saturation of Tight Reservoir |
| CN111208053A (en) * | 2020-03-20 | 2020-05-29 | 中国石油大学(北京) | Reservoir micro-capillary porosity determination method based on constant-pressure mercury-pressing experiment |
| CN111521539A (en) * | 2020-05-14 | 2020-08-11 | 中国地质大学（武汉） | Quantitative characterization method for different types of pore structures in compact conglomerate reservoir |
Non-Patent Citations (1)
| Title |
|---|
| 公言杰 等: "致密油流动孔隙度下限-高压压汞技术在松辽盆地南部白垩系泉四段的应用", 《石油勘探与开发》 * |
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| Samarasinghe et al. | Permeability and consolidation of normally consolidated soils | |
| CN105243182B (en) | Fine and close oil pressure splits the dynamic holdup computational methods of horizontal well | |
| CN107063967B (en) | A kind of saturation based on microscopic void channel/Unsaturated Hydraulic Conductivity prediction technique | |
| CN110598167B (en) | Processing method of oil-water relative permeability experimental data of low-permeability reservoir | |
| CN107462936B (en) | Utilize the method for pressure monitoring Data Inversion low permeability reservoir non-Darcy percolation law | |
| CN109030311A (en) | Based on nuclear magnetic resonance T2Compose the pore structure classification and recognition methods of sensitive parameter | |
| CN110096718B (en) | Method for obtaining volume of karst cave in carbonate reservoir | |
| CN111353205B (en) | Method for calculating formation pressure and dynamic productivity of water-producing gas well of tight gas reservoir | |
| CN108982320B (en) | Method for calculating permeability of reservoir with complex pore structure by using particle size parameters | |
| CN105574320A (en) | Evaluation method for effective seepage capability of low-permeability sandstone reservoir | |
| CN104330344A (en) | Core gas-water two-phase flow dynamic test method and device | |
| CN108133086A (en) | Water Fractured Gas Wells fracture half-length's inversion method is produced in a kind of stress sensitive reservoir | |
| CN109488282A (en) | Can dynamic reserve physical property lower limit determination method | |
| CN108133087A (en) | A kind of Gas-water phases seepage stress sensitivity reservoir original permeability inversion method | |
| CN113155694A (en) | Reservoir flow porosity determination method based on constant-pressure mercury-pressing experiment | |
| CN112257349B (en) | Method for judging whether tight sandstone movable water-gas reservoir gas well has development value | |
| CN109490162B (en) | Dense reservoir capillary pressure calculation method under stress sensitive condition | |
| CN112943176A (en) | Method for measuring gas-oil relative permeability curve for simulating injection and production of oil reservoir type gas storage | |
| CN104407397A (en) | Method for determining lower limit of physical property of compact oil and gas reservoir | |
| CN112395816A (en) | Polymer flooding reservoir interference well testing analysis method | |
| CN111208053A (en) | Reservoir micro-capillary porosity determination method based on constant-pressure mercury-pressing experiment | |
| CN111208048A (en) | Jamin effect dynamic change quantitative characterization method based on phase permeation test | |
| CN115481357A (en) | Dense gas reservoir capacity calculation method considering dynamic change of water saturation | |
| CN109063334B (en) | Fluid-solid coupling model construction method of low-permeability porous medium material | |
| CN111693425B (en) | Rock core film bound water saturation determination method based on mercury intrusion curve |
Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| PB01 | Publication | ||
| PB01 | Publication | ||
| SE01 | Entry into force of request for substantive examination | ||
| SE01 | Entry into force of request for substantive examination | ||
| RJ01 | Rejection of invention patent application after publication | ||
| RJ01 | Rejection of invention patent application after publication |
Application publication date: 20210723 |