CN109060639A - A kind of measuring method of long cores permeability saturation curve - Google Patents
A kind of measuring method of long cores permeability saturation curve Download PDFInfo
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- CN109060639A CN109060639A CN201811166808.1A CN201811166808A CN109060639A CN 109060639 A CN109060639 A CN 109060639A CN 201811166808 A CN201811166808 A CN 201811166808A CN 109060639 A CN109060639 A CN 109060639A
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- 238000000034 method Methods 0.000 title claims abstract description 40
- 230000035699 permeability Effects 0.000 title claims abstract description 39
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 74
- 239000007788 liquid Substances 0.000 claims abstract description 51
- 239000011435 rock Substances 0.000 claims abstract description 40
- 238000002347 injection Methods 0.000 claims abstract description 17
- 239000007924 injection Substances 0.000 claims abstract description 17
- 239000011148 porous material Substances 0.000 claims abstract description 16
- 238000006073 displacement reaction Methods 0.000 claims abstract description 12
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 claims description 14
- 239000011780 sodium chloride Substances 0.000 claims description 13
- 238000009738 saturating Methods 0.000 claims description 5
- 230000008569 process Effects 0.000 claims description 4
- 238000007789 sealing Methods 0.000 claims description 4
- 239000012267 brine Substances 0.000 claims description 3
- 230000008859 change Effects 0.000 claims description 3
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 claims description 3
- 238000003556 assay Methods 0.000 claims 2
- 238000004519 manufacturing process Methods 0.000 abstract description 15
- 239000012530 fluid Substances 0.000 abstract description 6
- 238000004364 calculation method Methods 0.000 abstract description 5
- 229920006395 saturated elastomer Polymers 0.000 abstract description 4
- 150000003839 salts Chemical class 0.000 abstract 2
- 238000009533 lab test Methods 0.000 abstract 1
- 238000002474 experimental method Methods 0.000 description 7
- 238000012360 testing method Methods 0.000 description 7
- 230000001186 cumulative effect Effects 0.000 description 4
- 238000005303 weighing Methods 0.000 description 4
- 239000012153 distilled water Substances 0.000 description 3
- 239000000203 mixture Substances 0.000 description 3
- 238000005259 measurement Methods 0.000 description 2
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 2
- 238000012986 modification Methods 0.000 description 2
- 230000004048 modification Effects 0.000 description 2
- UXVMQQNJUSDDNG-UHFFFAOYSA-L Calcium chloride Chemical compound [Cl-].[Cl-].[Ca+2] UXVMQQNJUSDDNG-UHFFFAOYSA-L 0.000 description 1
- 239000006004 Quartz sand Substances 0.000 description 1
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 description 1
- 230000033558 biomineral tissue development Effects 0.000 description 1
- 239000001110 calcium chloride Substances 0.000 description 1
- 229910001628 calcium chloride Inorganic materials 0.000 description 1
- 239000003153 chemical reaction reagent Substances 0.000 description 1
- 238000011161 development Methods 0.000 description 1
- 230000018109 developmental process Effects 0.000 description 1
- 238000010586 diagram Methods 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 238000009472 formulation Methods 0.000 description 1
- XLYOFNOQVPJJNP-ZSJDYOACSA-N heavy water Substances [2H]O[2H] XLYOFNOQVPJJNP-ZSJDYOACSA-N 0.000 description 1
- 229910017053 inorganic salt Inorganic materials 0.000 description 1
- 239000000463 material Substances 0.000 description 1
- 239000003345 natural gas Substances 0.000 description 1
- 238000010606 normalization Methods 0.000 description 1
- 239000003129 oil well Substances 0.000 description 1
- 239000003209 petroleum derivative Substances 0.000 description 1
- 238000011084 recovery Methods 0.000 description 1
- 238000011160 research Methods 0.000 description 1
- 238000004088 simulation Methods 0.000 description 1
Classifications
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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
-
- 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
- G01N15/088—Investigating volume, surface area, size or distribution of pores; Porosimetry
- G01N15/0893—Investigating volume, surface area, size or distribution of pores; Porosimetry by measuring weight or volume of sorbed fluid, e.g. B.E.T. method
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N5/00—Analysing materials by weighing, e.g. weighing small particles separated from a gas or liquid
- G01N5/02—Analysing materials by weighing, e.g. weighing small particles separated from a gas or liquid by absorbing or adsorbing components of a material and determining change of weight of the adsorbent, e.g. determining moisture content
- G01N5/025—Analysing materials by weighing, e.g. weighing small particles separated from a gas or liquid by absorbing or adsorbing components of a material and determining change of weight of the adsorbent, e.g. determining moisture content for determining moisture content
-
- 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
- G01N2015/0866—Sorption
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- Chemical & Material Sciences (AREA)
- Physics & Mathematics (AREA)
- General Health & Medical Sciences (AREA)
- Life Sciences & Earth Sciences (AREA)
- Analytical Chemistry (AREA)
- Biochemistry (AREA)
- Health & Medical Sciences (AREA)
- General Physics & Mathematics (AREA)
- Immunology (AREA)
- Pathology (AREA)
- Dispersion Chemistry (AREA)
- Fluid Mechanics (AREA)
- Investigation Of Foundation Soil And Reinforcement Of Foundation Soil By Compacting Or Drainage (AREA)
Abstract
The invention discloses a kind of measuring methods of long cores permeability saturation curve.Described method includes following steps: measuring the pore volume of rock core；Displacement is carried out to rock core using salt water, interval collects production fluid and surveys conductivity, when conductivity value is no longer changed, stops injection；The relation curve between the conductivity value and salt water injection pore volume of production fluid is drawn, and then judges the homogenieity of rock core；Rock core is placed vertically, inject oil from the top of rock core and is saturated, liquid to no aquatic products is connect from the bottom of rock core and goes out, measures output liquid measure, calculates irreducible water saturation；From the bottom of rock core, injection water carries out water drive oil, and liquid is connect at the top of rock core, aqueous oil content and injection pressure, calculation of water gas relative permeability in different time periods is recorded, obtains the permeability saturation curve of rock core.For small rock core, the method for the present invention is more accurate to the metering of experimental data, and precision is higher, while carrying out oil reservoir simulating lab test using the biggish long cores of scale and being more in line with reality.
Description
Technical Field
The invention relates to a method for measuring a relative permeability curve of a long core, belonging to the field of petroleum and natural gas engineering.
Background
The relative permeability curve is one of the most important data in the basic research work of oil reservoirs, and the yield, the water-oil ratio, the water production rule, the oil displacement efficiency, the oil recovery rate and the like of an oil well can be predicted in different development stages. The accuracy of the method directly influences the understanding of people on the oil-water displacement characteristics of the oil reservoir and various calculations, so that the correct calculation of the oil-water relative permeability curve of the oil reservoir is very important work. At present, for the determination of a relative permeability curve, the relative permeability curve is mostly determined by a standard SY/T5345-2007 'method for determining the relative permeability of two-phase fluid in rock', a small natural cored core is mostly adopted, for example, a patent with the application number of 201611094637.7 discloses a method for determining a gas-water relative permeability curve by a compact sandstone steady-state method, and the small core is adopted; in order to overcome the end effect, a plurality of small cores are spliced into a long core in the literature, namely phase permeability curve calculation at different positions in long core displacement, but the calculation of the permeability of the core is too complex. Meanwhile, the measurement requirement of the small core test relative permeability curve on the produced liquid is high, errors are easy to generate, and the condition of a thick oil layer cannot be simulated by adopting the small core.
Disclosure of Invention
The invention aims to provide a method for measuring a relative permeability curve of a large-size long core.
The method for measuring the relative permeability curve of the long core provided by the invention comprises the following steps:
(1) measuring the dry weight of the core, vacuumizing the core, saturating water, and measuring the wet weight of the core to further obtain the pore volume of the core;
the length of the core is 20-30 cm;
(2) carrying out constant-speed displacement on the rock core by adopting saline water, collecting output liquid at intervals, measuring the conductivity value, and stopping injecting the saline water when the conductivity value of the output liquid does not change any more; drawing a relation curve between the conductivity value of the produced liquid and the volume of the injection pores of the saline water, and further judging the homogeneity of the rock core;
(3) vertically placing the core, injecting oil from the top of the core and saturating the core, receiving liquid from the bottom of the core until no water is produced, measuring the produced liquid amount, and calculating the saturation of the irreducible water;
(4) injecting water from the bottom of the rock core for water flooding, receiving liquid from the top of the rock core, recording the water-containing oil content and the injection pressure in different time periods, and calculating the relative permeability of oil and water so as to obtain a relative permeability curve of the rock core.
In the measuring method, in the step (1), the dry weight and the wet weight of the core are measured by using an electronic balance; vacuumizing the rock core until the critical pressure standard value is-0.092 MPa, and weighing the mass M of the rock core after saturated water1Determining its pore volume V ═ M (M)1ˊ－M1)/ρWater (W)，M1Representing the mass of the core before saturation with water.
In the above-mentioned measuring method, the step (2) may be carried out according to the following steps: weighing required distilled water and inorganic salt by using an electronic balance, preparing saline water into a set mineralization degree, measuring the conductivity value of the saline water by using a conductivity meter, fully filling the prepared saline water in an intermediate container, sequentially connecting an ISCO pump, the intermediate container and a rock core by using pipelines, injecting the saline water from the inlet end of the rock core at the speed of v mL/min by using the ISCO pump for displacement, fixing the liquid receiving time interval, subpackaging produced liquid into a plurality of test tubes according to the liquid receiving sequence, measuring the conductivity of the produced liquid until the conductivity value is stable, for example, t s every interval, sequentially connecting the liquid at the outlet end of the rock core by using small test tubes until the conductivity value of the produced liquid is stable, wherein the injection amount is not less than 1 time of pore volume (1PV), continuously measuring the conductivity value of the produced liquid in the same time interval by using a DDS-11A digital conductivity meter, and recording the injection time corresponding to each conductivity value, and drawing a relation curve of the conductivity value and the volume of the injected pores, and testing the homogeneity of the rock core.
In the above determination method, in the step (3), the irreducible water saturation is calculated according to the following formula:
Swi＝(vˊ×T-Vwater)/Voil；
in the formula, VwaterIndicating the quantity of water produced, VoilThe unit of the produced oil is mL;
v' is the flow rate of the injected oil in mL/min;
t represents the injection time in min.
In the above-mentioned measuring method, the step (4) may be carried out according to the following steps: closing a horizontal valve at the inlet and outlet end of the rock core, vertically placing the rock core, opening the horizontal valve at the inlet and outlet end, performing saturated oil at the flow velocity of v' mL/min from the bottom end of the rock core, terminating liquid at the top end of the rock core, adding joint sealing liquid at intervals (indicating the initial liquid-receiving period, the liquid-receiving interval time is short, and the liquid-receiving interval time gradually increases later) at the initial water-meeting period, and sequentially adding the joint sealing liquid at intervals according to the interval t at each interval1min、t2min、t3min、t4min…(t1<t2<t3<t4<…) receiving the liquid until no oil is produced, recording the pressure difference in the displacement process, and calculating the water content and the content of the produced liquidAnd calculating the relative permeability of the water phase Krw and the relative permeability of the oil phase Kro at each moment, and the water saturation Sw at the outlet end of the rock sample.
Further, according to the experimental steps, the data of the produced liquid and the collected pressure are processed by a J.B.N method, and finally a relative permeability curve is obtained.
The adopted J.B.N method relates to the following formula:
wherein,
fo(Sw) -oil content, expressed in decimal numbers;
-dimensionless cumulative oil production, expressed as a fraction of pore volume;
-dimensionless cumulative fluid production expressed as a fraction of pore volume;
i-relative injection capability, also known as flow capability ratio;
Qoinitial moment rock sample outlet end face oil production flow rate, (cm)3/s)；
The flow rate of the produced liquid at the outlet end surface of the rock sample at the moment Q (t) -t, and Q (t) -Q in the constant speed method experimento，(cm3/s)；
ΔPo-initial driving differential pressure, (MPa);
the value of displacement pressure difference at time Δ P (t) -t, and Δ P (t) ═ Δ P in constant pressure experimento，(MPa)；
SwiIrreducible water saturation, expressed in decimal fraction;
Sweand the water saturation of the end face of the rock sample outlet is expressed by decimal.
The determination method of the invention has the advantages that: the invention provides a method for measuring a relative permeability curve of a long core, which is more accurate in measurement of experimental data and higher in precision compared with a small core, and meanwhile, the method is more practical when the long core with larger scale is adopted to carry out an indoor simulation experiment of an oil reservoir.
Drawings
Fig. 1 is a schematic diagram of the dimensions of a long core.
Fig. 2 is a core homogeneity test chart.
Figure 3 is a graph of production fluid data.
FIG. 4 is a graph of relative permeability obtained from experiments conducted using the method of the present invention.
FIG. 5 is a graph comparing a normalized calculated relative permeability curve to an experimentally obtained relative permeability curve.
Detailed Description
The experimental procedures used in the following examples are all conventional procedures unless otherwise specified.
Materials, reagents and the like used in the following examples are commercially available unless otherwise specified.
The method comprises the steps of manufacturing an artificial core by using quartz sand with a single mesh number of 60-80 meshes, measuring a long core with the core size of 4.5cm multiplied by 29.66cm, weighing dry weight, vacuumizing saturated distilled water until the critical pressure standard value is-0.092 MPa, fully saturating the distilled water, weighing, and calculating the pore volume to be 129.11 mL. Brine was prepared using 10L of distilled water, and the composition is shown in the following table.
TABLE 1 brine formulation
| Composition (I) | Content (mg/L) |
| CaCl2:2H2O | 700 |
| NaCl | 5000 |
Preparing saline water with the salinity of 5700mg/L, measuring the conductivity value of 9000 mus/cm by using a DDS-11A digital display conductivity meter, horizontally placing a core, connecting an ISCO pump, an intermediate container and the core by using pipelines in sequence, injecting saline water into the core at the speed of 4mL/min by using the ISCO pump for displacement, connecting liquid at the outlet end of the core in sequence by using test tubes at the interval time of 1min, measuring the conductivity value of the output liquid in the test tubes until the conductivity value is not changed any more, and stopping injection, wherein the injection amount is 3 times of the pore volume. The conductivity of the output liquid in each time interval is measured in turn by using a DDS-11A digital display conductivity meter, and a relation curve of the conductivity value of the output liquid and the volume of the injected pores is drawn, as shown in figure 2.
According to the method provided by the invention patent application with the application number of 2016109617561 (the invention name is: a method for evaluating the heterogeneous degree of the core), the fact that the core belongs to the homogeneous core is judged from the conductivity change chart. The core is vertically placed, saturated oil is carried out from the top of the core at the flow rate of 0.2mL/min until the pressure is stable and water does not flow out, the water yield and the stable pressure are recorded, and the saturation of the irreducible water is calculated. Then, oil displacement with water is carried out from the bottom of the core at the flow rate of 0.2mL/min, production liquid data is collected every 20min, sealing liquid is added at intervals when water is just started to meet, liquid is collected every 5min, liquid is collected every 10min after 20 liquid is collected, liquid is collected every 20min after 10 liquid is collected, liquid is collected every 10 liquid is collected every 40min after 10 liquid is collected, liquid is collected every 1h after 10 liquid is collected until the water content in the production liquid reaches 98%, the production liquid data and the injection pressure are recorded, and a relative permeability curve is calculated, as shown in fig. 4.
The resulting production data are shown in figure 3.
And calculating the relative permeability Krw of the water phase and the relative permeability Kro of the oil phase at each moment and the water saturation Sw of the outlet end of the rock sample by using a J.B.N method.
Wherein,
fo(Sw) -oil content, expressed in decimal numbers;
-dimensionless cumulative oil production, expressed as a fraction of pore volume;
-dimensionless cumulative fluid production expressed as a fraction of pore volume;
i-relative injection capability, also known as flow capability ratio;
Qoinitial moment rock sample outlet end face oil production flow rate, (cm)3/s)；
The flow rate of the produced liquid at the outlet end surface of the rock sample at the moment Q (t) -t, and Q (t) -Q in the constant speed method experimento，(cm3/s)；
ΔPo-initial driving differential pressure, (MPa);
the value of displacement pressure difference at time Δ P (t) -t, and Δ P (t) ═ Δ P in constant pressure experimento，(MPa)；
SwiIrreducible water saturation, expressed in decimal fraction;
Sweand the water saturation of the end face of the rock sample outlet is expressed by decimal.
In order to verify the accuracy of the curve, a repeated experiment was performed by using the same method based on the above-described examples. Meanwhile, a normalization method is adopted to process the relative permeability curve, and the obtained result is shown in fig. 5.
Kro＝a(1-SwD)m
Wherein,
SWD-normalizing the water saturation;
Swi-irreducible water saturation;
Swo-residual oil saturation;
m, n-parameters relating to the core.
As can be seen from comparing FIG. 4 and FIG. 5, the normalized relative permeability curve has a trend substantially consistent with that of the relative permeability curve obtained by the method of the present invention, which indicates that the relative permeability curve obtained by the method of the present invention is accurate, and the established long core relative permeability curve determination method is feasible.
The foregoing is only a preferred embodiment of the present invention, and it should be noted that the present invention is not limited to the above-mentioned embodiment, and further modifications can be made without departing from the principle of the present invention, and these modifications should also be construed as the protection scope of the present invention.
Claims (4)
1. A method for measuring a relative permeability curve of a long core comprises the following steps:
(1) measuring the dry weight of the core, vacuumizing the core, saturating water, and measuring the wet weight of the core to further obtain the pore volume of the core;
the length of the core is 20-30 cm;
(2) carrying out constant-speed displacement on the rock core by adopting saline water, collecting output liquid at intervals, measuring the conductivity value, and stopping injecting the saline water when the conductivity value of the output liquid does not change any more; drawing a relation curve between the conductivity value of the produced liquid and the volume of the injection pores of the saline water, and further judging the homogeneity of the rock core;
(3) vertically placing the core, injecting oil from the top of the core and saturating the core, receiving liquid from the bottom of the core until no water is produced, measuring the produced liquid amount, and calculating the saturation of the irreducible water;
(4) injecting water from the bottom of the rock core for water flooding, receiving liquid from the top of the rock core, recording the water-containing oil content and the injection pressure in different time periods, and calculating the relative permeability of oil and water so as to obtain a relative permeability curve of the rock core.
2. The method for measuring according to claim 1, wherein: in the step (2), the brine is injected at a constant rate;
and continuously measuring the conductivity value of the output liquid in the same time interval by adopting a DDS-11A digital display conductivity meter.
3. The assay method according to claim 1 or 2, characterized in that: in step (3), the irreducible water saturation is calculated according to the following formula:
Swi＝(vˊ×T-Vwater)/Voil；
in the formula, VwaterIndicating the quantity of water produced, VoilThe unit of the produced oil is mL;
v' is the flow rate of the injected oil in mL/min;
t represents the injection time in min.
4. The assay method according to any one of claims 1 to 3, wherein: in the step (4), in the water flooding process, adding the sealing liquid at intervals at the initial stage of water breakthrough until no oil is produced, recording the pressure difference in the water flooding process, calculating the water content and the oil content in the produced liquid, and calculating the water phase relative permeability, the oil phase relative permeability and the rock sample outlet end water saturation at each moment by adopting a J.B.N method.
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Cited By (6)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN109632604A (en) * | 2019-01-04 | 2019-04-16 | 中国海洋石油集团有限公司 | A kind of pore scale is to rock core scale Relative Permeabilty From Polymer Displacement Experiment method of roughening |
| CN110130874A (en) * | 2019-06-03 | 2019-08-16 | 中国石油大学(北京) | The determination method and device that grease mutually seeps in Carbonate Reservoir water drive |
| CN111255444A (en) * | 2020-01-09 | 2020-06-09 | 中海石油(中国)有限公司 | Method for measuring relative permeability of oil and gas in stratum |
| CN112081588A (en) * | 2020-10-26 | 2020-12-15 | 西南石油大学 | Method for judging viscosity change of chemical system in relative permeability curve |
| CN112505298A (en) * | 2020-12-01 | 2021-03-16 | 西南石油大学 | In-situ test method for compact oil gas storage and production performance parameters |
| CN113588513A (en) * | 2021-07-19 | 2021-11-02 | 西南石油大学 | Method for evaluating influence of loose sandstone structure on phase permeation curve form |
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| CN105606509A (en) * | 2015-12-22 | 2016-05-25 | 中国石油大学(华东) | Measuring method of high-temperature oil-water relative permeability of heavy oil reservoir |
| CN106525690A (en) * | 2016-12-02 | 2017-03-22 | 中国石油天然气股份有限公司 | Method for measuring gas-water relative permeability curve by tight sandstone steady-state method |
| CN106525685A (en) * | 2016-10-28 | 2017-03-22 | 西南石油大学 | Method used for evaluating heterogeneous degree of rock core |
| CN108444884A (en) * | 2018-03-26 | 2018-08-24 | 中国石油化工股份有限公司 | Oil relative permeability curve characterizing method based on Harris models |
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| Publication number | Priority date | Publication date | Assignee | Title |
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| CN105606509A (en) * | 2015-12-22 | 2016-05-25 | 中国石油大学(华东) | Measuring method of high-temperature oil-water relative permeability of heavy oil reservoir |
| CN106525685A (en) * | 2016-10-28 | 2017-03-22 | 西南石油大学 | Method used for evaluating heterogeneous degree of rock core |
| CN106525690A (en) * | 2016-12-02 | 2017-03-22 | 中国石油天然气股份有限公司 | Method for measuring gas-water relative permeability curve by tight sandstone steady-state method |
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Cited By (10)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN109632604A (en) * | 2019-01-04 | 2019-04-16 | 中国海洋石油集团有限公司 | A kind of pore scale is to rock core scale Relative Permeabilty From Polymer Displacement Experiment method of roughening |
| CN109632604B (en) * | 2019-01-04 | 2021-06-15 | 中国海洋石油集团有限公司 | Method for coarsening relative permeability of polymer flooding from pore size to core size |
| CN110130874A (en) * | 2019-06-03 | 2019-08-16 | 中国石油大学(北京) | The determination method and device that grease mutually seeps in Carbonate Reservoir water drive |
| CN111255444A (en) * | 2020-01-09 | 2020-06-09 | 中海石油(中国)有限公司 | Method for measuring relative permeability of oil and gas in stratum |
| CN111255444B (en) * | 2020-01-09 | 2023-04-28 | 中海石油(中国)有限公司 | Stratum oil gas relative permeability determination method |
| CN112081588A (en) * | 2020-10-26 | 2020-12-15 | 西南石油大学 | Method for judging viscosity change of chemical system in relative permeability curve |
| CN112081588B (en) * | 2020-10-26 | 2022-02-15 | 西南石油大学 | Method for judging viscosity change of chemical system in relative permeability curve |
| CN112505298A (en) * | 2020-12-01 | 2021-03-16 | 西南石油大学 | In-situ test method for compact oil gas storage and production performance parameters |
| CN112505298B (en) * | 2020-12-01 | 2022-02-15 | 西南石油大学 | In-situ test method for compact oil gas storage and production performance parameters |
| CN113588513A (en) * | 2021-07-19 | 2021-11-02 | 西南石油大学 | Method for evaluating influence of loose sandstone structure on phase permeation curve form |
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Application publication date: 20181221 |
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