CN114139470B - Method for calculating gas relative permeability of tight sandstone gas reservoir - Google Patents
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- 230000035699 permeability Effects 0.000 title claims abstract description 141
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- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 52
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- 239000007788 liquid Substances 0.000 claims abstract description 34
- 239000011148 porous material Substances 0.000 claims abstract description 5
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- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 claims description 16
- 229910052757 nitrogen Inorganic materials 0.000 claims description 8
- 238000006073 displacement reaction Methods 0.000 claims description 5
- 229920006395 saturated elastomer Polymers 0.000 claims description 5
- 238000012937 correction Methods 0.000 claims description 4
- 239000008346 aqueous phase Substances 0.000 claims description 3
- 238000002347 injection Methods 0.000 claims description 3
- 239000007924 injection Substances 0.000 claims description 3
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- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 description 4
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- TWRXJAOTZQYOKJ-UHFFFAOYSA-L Magnesium chloride Chemical compound [Mg+2].[Cl-].[Cl-] TWRXJAOTZQYOKJ-UHFFFAOYSA-L 0.000 description 2
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Abstract
The invention discloses a method for calculating the relative gas permeability of a tight sandstone gas reservoir, which comprises the following steps: calculating the gas phase permeability under different gas saturation according to the gas relative permeability value and the gas phase permeability value under the residual water state; according to the gas saturation, calculating the porosity under different gas saturation; according to the relation between the permeability and the pore radius, calculating the quality index of the reservoir under different gas saturation; calculating the liquid permeability under different gas saturation according to the relation between the initial liquid permeability of the core and the reservoir quality index, namely converting the gas phase permeability into the liquid permeability under the same gas saturation; the relative gas permeability is corrected and plotted. According to the method, the influence of gas slippage is considered, the gas phase permeability is converted into the liquid phase permeability under different gas saturation degrees to perform the phase permeability calculation, so that the gas-water phase permeability change rule of the tight sandstone gas reservoir can be mastered more accurately, and a basis is provided for gas reservoir development.
Description
Technical Field
The invention relates to the technical field of oil and gas reservoir development, in particular to a method for calculating gas relative permeability of a tight sandstone gas reservoir.
Background
The relative permeability is typically used to characterize the pore structure, saturation distribution and wettability of the reservoir, and the gas-water permeability may characterize the relative flow capacity of the gas-water in the reservoir. Therefore, it is important to obtain the gas-water relative permeability under different conditions accurately to better understand the internal law of gas flow in the reservoir.
In the existing gas relative permeability measurement method, the influence of the slip effect is not fully considered, so that the gas relative permeability can be overestimated, and the final data is not corrected, so that larger errors are easily generated.
Disclosure of Invention
In order to solve the technical problems, the invention provides the following technical scheme:
a method for calculating the relative gas permeability of a tight sandstone gas reservoir comprises the following steps:
S1, calculating gas phase permeability under different gas saturation according to the gas relative permeability value and the gas phase permeability value under the residual water state; the gas relative permeability value is calculated according to a JBN formula, and the gas phase permeability value in the residual water state is calculated according to a calculation formula of gas permeability;
s2, calculating the porosity under different gas saturation according to the gas saturation;
s3, calculating the quality index of the reservoir stratum under different gas saturation according to the relation between the permeability and the pore radius;
S4, calculating the liquid permeability of the core in the current region under different gas saturation degrees according to the relation between the initial liquid permeability of the core and the quality index of the reservoir, namely converting the gas permeability into the liquid permeability under the same gas saturation degree;
S5, correcting the relative gas permeability obtained according to the JBN formula in the S1, and drawing a relative gas permeability curve.
Preferably, in step S1, the formula for calculating the gas phase permeability at different gas saturation levels is as follows:
where K rgi is the relative permeability of the gas at different gas saturation levels, K rg(swi) is the relative permeability of the gas at irreducible water saturation level, and K g(swi) is the gas phase permeability at irreducible water saturation level.
Preferably, in step S2, the calculation formula of the porosity at different gas saturation levels is as follows:
Wherein phi g is the core porosity, and S gi is different gas saturation.
Preferably, in step S3, the calculation formula of the reservoir quality index at different gas saturation levels is as follows:
Wherein K gi is gas phase permeability at different gas saturation levels, and phi gi is porosity at different gas saturation levels.
Preferably, in step S4, the initial liquid permeability of the core is the initial water phase permeability of the core measured after the core in the current region is fully saturated with water, and the relationship between the initial liquid permeability of the core and the reservoir quality index is as follows:
wherein RQI is the reservoir quality index, and a and b are fitting parameters.
Preferably, in step S5, the correction formula of the relative gas permeability is as follows:
Wherein, K wi is the liquid permeability under different gas saturation, and K w is the initial liquid permeability of the core.
According to the method for calculating the gas relative permeability of the tight sandstone gas reservoir, disclosed by the invention, the influence of gas slippage is considered, the gas phase permeability is converted into the liquid phase permeability under different gas saturation degrees to perform phase permeability calculation, so that the gas water phase permeability change rule of the tight sandstone gas reservoir can be mastered more accurately, and a basis is provided for gas reservoir development.
Drawings
FIG. 1 is a diagram of an experimental apparatus for determining the relative permeability of a gas in an embodiment of the present invention;
FIG. 2 is a graph of the exponentiation of the initial fluid permeability of the core of the current region and the reservoir quality index in an embodiment of the present invention;
FIG. 3 is a graph showing the relative permeability of gases before and after correction in an embodiment of the present invention.
Reference numerals
1. Double-cylinder constant-speed constant-pressure displacement pump; 2. a nitrogen cylinder; 3. a pressure reducing valve; 4. an intermediate container; 5. a pressure gauge; 6. a core holder; 7. a gas-liquid separator; 8. a wet flow meter; 9. a soap foam flowmeter; 10. and a surrounding pressure pump.
Detailed Description
The technical scheme of the invention is further described below with reference to the accompanying drawings and examples.
The invention provides a method for calculating the relative gas permeability of a tight sandstone gas reservoir, wherein the determination of the relative gas permeability and the gas saturation can be obtained by an unsteady state method or a steady state method. The invention is determined by an unsteady state method, and specifically comprises the following steps:
s1, calculating a gas relative permeability value and a gas phase permeability value under a residual water state according to a JBN formula and a gas permeability measurement formula, and then calculating the gas phase permeability under different gas saturation;
Wherein K gi is gas phase permeability under different gas saturation, and unit mD; k rgi is the relative permeability of gases at different gas saturation levels; k rgi（swi） is the relative permeability of the gas at irreducible water saturation; k g（swi） is the gas phase permeability in mD at irreducible water saturation.
S2, calculating the porosity under different gas saturation according to the gas saturation;
Wherein phi gi is the porosity at different gas saturation; phi g is the core porosity; s gi are different gas saturation levels.
S3, calculating the quality index of the reservoir stratum under different gas saturation according to the relation between the permeability and the pore radius;
Wherein K gi is gas phase permeability at different gas saturation levels, and phi gi is porosity at different gas saturation levels.
S4, measuring initial liquid permeability of the rock core in the state of full saturated water of the rock core in the current region, and calculating the liquid permeability of the rock core at each gas saturation according to the relation between the initial liquid permeability of the rock core and the quality index of the reservoir, namely converting the gas phase permeability into the liquid permeability at the same gas saturation;
wherein RQI is the reservoir quality index, and a and b are fitting parameters.
S5, correcting the relative gas permeability obtained according to the JBN formula, and drawing a relative gas permeability curve.
Wherein, K wi is the liquid permeability under different gas saturation, and K w is the initial liquid permeability of the core.
The above method is described below in connection with specific experimental procedures and calculation data.
1. Core selection
And (3) drying the natural rock core obtained on site to constant weight, and then measuring basic physical parameters such as length, diameter, porosity, gas permeability and the like, wherein the porosity and the gas permeability are measured by adopting nitrogen at room temperature. Wherein, the gas permeability is obtained according to the following formula:
K g is the core gas permeability measured by nitrogen, and the unit is mD; q g is the gas flow rate, unit mL/s; p a is the atmospheric pressure, in MPa; mu g is the viscosity of nitrogen under experimental conditions in mPas; l is the length of the core and is in cm; a is the section area of the core, and cm 2;P1、P2 is the pressure of the inlet end and the outlet end of the core, and MPa.
Table 1 shows the core base data used for the experiments.
Table 1 core base data table
2. Fluid selection
Preparing a standard saline water (NaCl: caCl 2:MgCl2·6H2 O=7:0.6:0.4) with the mineralization degree of 125000mg/L according to the oil and gas industry standard SY/T5358-2010 reservoir sensitivity flow experiment evaluation method, and filtering the standard saline water by adopting a filter membrane with the thickness of 0.45 mu m through a sand core funnel before an experiment; the experimental gas sample is high-purity nitrogen with the purity of 99.999 percent.
3. Experimental device
The experimental device for measuring the relative permeability of the gas phase and the water phase by adopting the unsteady state method is shown in figure 1, and comprises a high-pressure displacement pump 1, a high-pressure gas source 2, a pressure reducing valve 3, an intermediate container 4 for containing stratum water, a pressure gauge 5, a core holder 6, a gas-liquid separator 7, gas meters 8 and 9 and a confining pressure pump 10. The core holder 6 is provided with two inlet ends, an outlet end and a confining pressure port, the high-pressure displacement pump 1 is connected with the middle container 4 for containing stratum water and is communicated with one side inlet end of the core holder, the high-pressure air source 2 is communicated with the other side inlet end of the core holder by regulating pressure through the pressure reducing valve 3, and the inlet of the core holder is provided with a pressure gauge 5 for monitoring pressure; the confining pressure pump 10 is connected with a confining pressure port of the core holder; the outlet end of the core holder is connected with a gas-liquid separation device 7, the water quantity is obtained through the scale of a measuring cylinder or by weighing, the air quantity is measured through a wet flowmeter 8 and a soap flowmeter 9, one of the two modes is selected in the process, the wet flowmeter 8 can be selected according to the air outlet condition, the wet flowmeter 8 is selected when the air flow is high, and the soap flowmeter 9 is selected when the air flow is low.
4. Saturated formation fluid
And vacuumizing the selected rock core for 4 hours, injecting simulated formation water, pressurizing to 20MPa, and maintaining for 12 hours to fully saturate the rock core.
5. Gas relative permeability measurement experiment
(1) The experimental process is carried out according to the unsteady-state method gas-water relative permeability measurement in the national industry standard GB/T28912-2012 method for measuring relative permeability of two-phase fluid in rock. And loading the core of saturated stratum water into a core holder, firstly emptying an inlet pipeline at a low flow rate, adding confining pressure to 5MPa, and if the inlet pressure slowly rises to be higher than 3MPa in the process, synchronously adjusting the confining pressure, and always keeping the confining pressure higher than the inlet pressure by 2MPa. The confining pressure is not changed as much as possible in the experimental process, and the stress influence is avoided.
(2) Simulating stratum water flooding at a certain flow rate (lower than a critical flow rate), and after the pressure and the flow are stable, measuring the initial water phase permeability of the core, wherein the calculation formula is as follows:
Wherein K w is the initial water phase permeability in mD; q w is the outlet end water phase flow rate, unit mL/s; ΔP is the differential pressure in MPa; mu w is the viscosity of the aqueous phase in mPas under the experimental conditions.
(3) And selecting the pressure of nitrogen injection according to the initial water phase permeability stabilization pressure (the pressure difference is required to ensure that the end effect can be overcome and turbulent flow is not generated), performing gas flooding, recording the flooding pressure, the flooding gas outlet quantity and the flooding water yield under different flooding time in the experimental process, performing gas flooding to a residual water state, and ending the experiment after measuring the effective gas permeability under the residual water.
6. Calculation of relative Permeability
(1) The relative permeability value of the gas is calculated according to the JBN formula.
Wherein V i is the accumulated water and gas yield at the moment i and is unit mL; deltaV wi is the water increment from i-1 time to i time, and is in units of mL; deltaV gi is the gas increment from i-1 time to i time, and is in units of mL; v i-1 is the accumulated water and gas yield at the moment i-1, and the unit is mL; ΔP is displacement differential pressure in MPa; f w(Sg) is the water content; Is the dimensionless accumulated water yield; /(I) Is the dimensionless accumulated liquid production amount; i is the relative injection capacity; k rw is the relative permeability of the aqueous phase; k rg is the relative permeability of the gas phase; s g is the saturation of the gas.
Taking the core 9 as an example, the initial water phase permeability K w = 0.1140mD, the residual underwater gas permeability K g(swi) =0.239 mD, and the gas relative permeability obtained by calculating according to the JBN formula are shown in table 2, and the gas relative permeability values are all higher due to the influence of the gas slip effect.
TABLE 2 results of gas-water relative permeability experiments (JBN formula calculation)
(2) The gas phase permeability under different gas saturation degrees is calculated according to the gas relative permeability value and the gas phase permeability value under the residual water state, the calculation formula is shown as follows, and the calculation result is shown as K gi in table 3.
(3) Based on the gas saturation, the porosity at different gas saturation was calculated as shown below, and the calculation result is shown in Table 3 as phi gi.
(4) According to the KC equation, the reservoir quality index at each gas saturation is calculated as shown below, and the results are shown in Table 3 as RQI gi.
(5) According to the relation between the initial liquid permeability of the core in the current region and the quality index of the reservoir, the liquid permeability under each gas saturation level is calculated, namely, the gas phase permeability is converted into the liquid permeability under the same gas saturation level, the relation is shown as follows, and the calculated liquid permeability under each gas saturation level is shown as K wi in the table 3. Fig. 2 shows the exponentiation of the initial liquid permeability and the reservoir quality index of the cores of the current regions 1-13, and the initial liquid measured permeability K w and the reservoir quality index value RQI of the cores of the current regions are shown in table 1.
，R2=0.9023
(6) Correcting the relative permeability of the gas and drawing a relative permeability curve. The relative permeability curves before and after correction are shown in fig. 3.
TABLE 3 gas-water relative permeability calibration experiment results (method calculation)
Finally, it should be noted that: the foregoing description is only illustrative of the preferred embodiments of the present invention, and although the present invention has been described in detail with reference to the foregoing description, it will be apparent to those skilled in the art that various modifications, equivalents, and alternatives to some of the features described in the foregoing description are intended to be included within the spirit and principles of the present invention.
Claims (1)
1. The method for calculating the gas relative permeability of the tight sandstone gas reservoir is characterized by comprising the following steps of:
S1, calculating gas phase permeability under different gas saturation according to the gas relative permeability value and the gas phase permeability value under the residual water state; the gas relative permeability value is calculated according to a JBN formula, and the gas phase permeability value in the residual water state is calculated according to a calculation formula of gas permeability;
s2, calculating the porosity under different gas saturation according to the gas saturation;
s3, calculating the quality index of the reservoir stratum under different gas saturation according to the relation between the permeability and the pore radius;
S4, calculating the liquid permeability of the core in the current region under different gas saturation degrees according to the relation between the initial liquid permeability of the core and the quality index of the reservoir, namely converting the gas permeability into the liquid permeability under the same gas saturation degree;
S5, correcting the relative gas permeability obtained according to the JBN formula in the S1, and drawing a relative gas permeability curve;
The gas permeability is obtained according to the following formula:
K g is the core gas permeability measured by nitrogen, and the unit is mD; q g is the gas flow rate, unit mL/s; p a is the atmospheric pressure, in MPa; mu g is the viscosity of nitrogen under experimental conditions in mPas; l is the length of the core and is in cm; a is the section area of the core, and cm 2;P1、P2 is the pressure of the inlet end and the outlet end of the core, and MPa;
the gas relative permeability values were calculated according to the JBN formula as follows:
wherein V i is the accumulated water and gas yield at the moment i and is unit mL; deltaV wi is the water increment from i-1 time to i time, and is in units of mL; deltaV gi is the gas increment from i-1 time to i time, and is in units of mL; v i-1 is the accumulated water and gas yield at the moment i-1, and the unit is mL; ΔP is displacement differential pressure in MPa; f w(Sg) is the water content; Is the dimensionless accumulated water yield; /(I) Is the dimensionless accumulated liquid production amount; i is the relative injection capacity; k rw is the relative permeability of the aqueous phase; k rg is the relative permeability of the gas phase; s g is the saturation of the gas;
in the step S1, the calculation formula of the gas phase permeability under different gas saturation is as follows:
Wherein, K rgi is the relative permeability of gas under different saturation levels, K rg(swi) is the relative permeability of gas under the saturation level of irreducible water, and K g(swi) is the gas phase permeability under the saturation level of irreducible water;
in the step S2, the calculation formula of the porosity under different gas saturation is as follows:
Wherein phi g is the core porosity, and S gi is different gas saturation;
In the step S3, the calculation formula of the reservoir quality index under different gas saturation is as follows:
Wherein K gi is gas phase permeability at different gas saturation levels, and phi gi is porosity at different gas saturation levels;
In the step S4, the initial liquid permeability of the core is the initial water phase permeability of the core measured after the core in the current region is fully saturated with water, and the relation between the initial liquid permeability of the core and the quality index of the reservoir is as follows:
Wherein RQI is a reservoir quality index, and a and b are fitting parameters;
in the step S5, the correction formula of the relative gas permeability is as follows:
；
Wherein, K wi is the liquid permeability under different gas saturation, and K w is the initial liquid permeability of the core.
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