CN114441403A - Free oil content determination method based on shale pore distribution - Google Patents
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- 239000011148 porous material Substances 0.000 title claims abstract description 132
- 238000000034 method Methods 0.000 title claims abstract description 43
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- 239000003921 oil Substances 0.000 claims abstract description 95
- 239000011435 rock Substances 0.000 claims abstract description 53
- QSHDDOUJBYECFT-UHFFFAOYSA-N mercury Chemical compound [Hg] QSHDDOUJBYECFT-UHFFFAOYSA-N 0.000 claims abstract description 38
- 229910052753 mercury Inorganic materials 0.000 claims abstract description 38
- 229930195733 hydrocarbon Natural products 0.000 claims abstract description 29
- 150000002430 hydrocarbons Chemical class 0.000 claims abstract description 29
- 239000004215 Carbon black (E152) Substances 0.000 claims abstract description 26
- 238000001179 sorption measurement Methods 0.000 claims abstract description 26
- 239000003079 shale oil Substances 0.000 claims abstract description 22
- 239000010779 crude oil Substances 0.000 claims abstract description 20
- 238000002474 experimental method Methods 0.000 claims abstract description 12
- 238000012900 molecular simulation Methods 0.000 claims abstract description 11
- 238000004458 analytical method Methods 0.000 claims abstract description 8
- 238000002347 injection Methods 0.000 claims abstract description 7
- 239000007924 injection Substances 0.000 claims abstract description 7
- 239000012530 fluid Substances 0.000 claims description 13
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- 239000002245 particle Substances 0.000 claims description 10
- 238000012360 testing method Methods 0.000 claims description 10
- 238000007872 degassing Methods 0.000 claims description 8
- 230000015572 biosynthetic process Effects 0.000 claims description 6
- 239000000203 mixture Substances 0.000 claims description 6
- ATUOYWHBWRKTHZ-UHFFFAOYSA-N Propane Chemical compound CCC ATUOYWHBWRKTHZ-UHFFFAOYSA-N 0.000 claims description 5
- 239000001307 helium Substances 0.000 claims description 5
- 229910052734 helium Inorganic materials 0.000 claims description 5
- SWQJXJOGLNCZEY-UHFFFAOYSA-N helium atom Chemical compound [He] SWQJXJOGLNCZEY-UHFFFAOYSA-N 0.000 claims description 5
- 238000004422 calculation algorithm Methods 0.000 claims description 4
- 238000000329 molecular dynamics simulation Methods 0.000 claims description 4
- 238000005303 weighing Methods 0.000 claims description 4
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 claims description 3
- 230000008859 change Effects 0.000 claims description 3
- 229910021389 graphene Inorganic materials 0.000 claims description 3
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- 230000035699 permeability Effects 0.000 description 1
- 230000000704 physical effect Effects 0.000 description 1
- 239000000843 powder Substances 0.000 description 1
- 238000003825 pressing Methods 0.000 description 1
- 239000001294 propane Substances 0.000 description 1
- 238000000197 pyrolysis Methods 0.000 description 1
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Abstract
The invention relates to the technical field of shale oil exploration and development, in particular to a method for measuring free oil content based on shale pore distribution. The method comprises the following steps: selecting a shale rock sample of a target block, and performing a high-pressure mercury injection experiment; obtaining the pore size distribution of the shale and the pore volume corresponding to each pore size; selecting a stratum crude oil sample of a target block, and carrying out hydrocarbon component analysis to obtain the mass fraction of hydrocarbon components; combining a molecular simulation technology to obtain the thickness and the characteristics of the organic pore adsorption layer under the crude oil; calculating the volume ratio of separated oil at different apertures; calculating the free oil content of the shale sample in pore size distribution; and calculating the total volume of the free oil of the core sample and the proportion of the total free oil in the total pore volume. The method accurately describes the content and the distribution rule of the free oil in the shale pores, has stronger reliability and accuracy, and provides effective technical support for evaluating the shale oil field resource amount and making a development scheme.
Description
Technical Field
The invention relates to the technical field of shale oil exploration and development, in particular to a method for measuring free oil content based on shale pore distribution.
Background
With the success of the American shale oil and gas revolution, the proportion of shale oil in the crude oil yield is higher and higher, and the shale oil becomes a key component for replacing the domestic resource yield. The shale oil reservoir is compact and low in permeability, the micro-nano pores are developed in a large quantity, and the shale oil utilization degree is low due to the influence of adsorption. The shale oil free oil content analysis technology is established, the distribution situation of the free oil in different shale pore sizes is clear, the resource evaluation of the shale oil is more accurate, and a foundation is provided for the formulation of a development scheme of the shale oil.
Chinese patent application CN110749644A discloses a shale free oil analysis device, which comprises a crushing component for placing and crushing a shale sample, a temperature control component for providing a specific temperature environment for the shale sample, and a signal detection processing component for detecting hydrocarbon substances escaping from the shale sample. Through the mode, the blocky shale sample is crushed into powder by using the high-hardness blade in the closed sample bin, so that the loss of hydrocarbons is reduced to the maximum extent, conditions are created for completely and accurately detecting the content of free oil, and meanwhile, gaseous hydrocarbons such as A, B, propane and the like and other hydrocarbons escape separately by using a low-temperature environment, so that the determination of gas-oil ratio (GOR) parameters of the shale sample can be realized, the evaluation of the oil-gas content of the shale is effectively realized, and the characterization parameters of the content of the free oil of the shale are obtained.
Chinese patent application CN106547966A discloses a shale oil adsorption capacity and movable capacity evaluation model and a building and application method thereof. The method is based on the capillary condensation theory, establishes a shale oil adsorption capacity and movable quantity evaluation model under the laboratory condition, and can quantitatively calculate the shale oil adsorption capacity
And a movable quantity Qc＝(βV2-kdS2hn)ρ2And the total amount of occurrence of Qt＝Qa+QcAnd the percentage ratio of each of the adsorption amount and the mobile amount; the method is characterized in that a model application method under reservoir conditions is established, the hydrocarbon adsorption capacity and the occurrence total amount are expressed as functions of porosity and apparent density, the hydrocarbon adsorption capacity, the movable amount and the percentage ratio of the movable amount are evaluated according to the distribution of the porosity and the oil saturation evaluated by logging data in the longitudinal direction of the shale reservoir, and the method is simple and easy to operate, high in accuracy, strong in operability and practicability and convenient for geological popularization and application.
At present, the research on the occurrence of shale oil in shale reservoirs mainly comprises the steps of analyzing the content of free oil by obtaining an S1 parameter through pyrolysis and researching the oil content in shale pores by a method of observation under a scanning electron microscope. However, on the basis of shale pore distribution, quantitative analysis of shale free oil is established aiming at different shale pore sizes and distributions, and systematic research and mature method research are less.
Disclosure of Invention
The invention aims to provide a new method for measuring the free oil content based on the shale pore distribution.
In order to achieve the purpose, the invention adopts the following technical scheme:
the invention provides a method for measuring free oil content based on shale pore distribution, which comprises the following steps: selecting a shale rock sample of a target block, and performing a high-pressure mercury injection experiment; obtaining the pore size distribution of the shale and the pore volume corresponding to each pore size; selecting a stratum crude oil sample of a target block, and performing hydrocarbon full-component analysis to obtain a hydrocarbon component mass fraction; combining a molecular dynamics simulation method to obtain the thickness and the characteristics of the organic pore adsorption layer under the crude oil; calculating the volume ratio of separated oil at different apertures; calculating the free oil content of the shale sample in pore size distribution; and calculating the total volume of the free oil of the core sample and the proportion of the total free oil in the total pore volume.
Preferably, the shale rock sample of the target block is selected, and the volume V of the rock sample is obtained by using a measurement methodbObtaining the volume V of rock sample particles by a helium hole methodgAnd subtracting the particle volume from the rock sample volume to obtain a rock sample pore volume Vp(ii) a Weighing the mass m of the rock sample by using a balance, and mixing m with VpInputting the mercury into a mercury intrusion test system to perform a high-pressure mercury intrusion test.
Further preferably, the pore radius R is obtained according to the high-pressure mercury intrusion test resultiAnd a pore radius RiCorresponding pore volume key parameters
Preferably, a single degassing experiment is performed on the formation crude oil of the target block to obtain the mass fraction of each hydrocarbon component, and the calculation formula is as follows:
in the formula, XfiIs the mole fraction of the i component of the formation fluid; wdIs the mass value of dead oil, g;
is the average relative molar mass of dead oilThe value of (1), g/mol; x is the number ofiIs the mole fraction of the dead oil i component; r is a molar gas constant of 8.3145MPa cm3/(mol·K)；yiThe mole fraction of gas i component, in dimensionless units, is evolved for a single degassing.
Preferably, the fluid composition is set according to the mass fraction of hydrocarbon components of the shale oil, based on a LAMMPS molecular simulation program, the temperature of the whole molecular simulation system is controlled to be the oil reservoir temperature by adopting a No é -Hoover algorithm, the simulation is carried out under the conditions of fixed molecular number, fixed volume and fixed temperature, so that the system is balanced, when the parameters of the total energy, the temperature, the pressure and the like of the system are not changed along with time, the molecular simulation system is determined to reach the balanced state, and the mass density distribution diagram of the organic pore adsorption layer and the thickness Ra of the adsorption layer under the reservoir crude oil are obtained.
Further preferably, let the fluid composition be CH4、C2H6、C3H8、C4H10、C5H12、C6H14、C7H16、C13H28Wherein the component higher than C7 is C13H28Instead, graphene is used to replace organic matter in shale reservoirs.
Preferably, the volume ratio of separated oil at different apertures is calculated by the formula:
wherein,
is a radius RiThe ratio of the pore diameter free oil to the pore volume, decimal fraction; ri is the pore radius, nm; ra is the thickness of the adsorption layer, nm; l is the characteristic length of the rock sample, cm.
Preferably, the calculation formula of the free oil content of the shale sample in the pore size distribution is as follows:
in the formula,
is a radius RiPore diameter of (2) free oil volume, cm3；
Is a radius RiPore size of (d), cm3。
Preferably, the calculation formula of the total volume of the free oil of the core sample is as follows:
wherein, VfIs the volume of total free oil in the rock sample, cm3。
Preferably, the calculation formula of the total pore volume entered by mercury in the rock sample and the proportion of the total free oil in the total pore volume is as follows:
wherein, VfIs the volume of total free oil in the rock sample, cm3；VpHgIs the total pore volume, cm, of the rock sample into which mercury enters3(ii) a Alpha is the ratio of the total free oil content of the sample to the total mercury pore volume.
The method comprises the steps of obtaining a shale pore distribution rule and pore volumes corresponding to the sizes of pores through a high-pressure mercury pressing experiment, obtaining shale oil hydrocarbon components through an oil-gas reservoir fluid physical property analysis method, setting fluid parameters according to the crude oil hydrocarbon components, calculating the thickness of a shale oil adsorption layer by combining a molecular simulation technology, calculating the proportion of free oil in the pore volumes under different pore radii, calculating the content of the free oil in each pore by combining the pore distribution rule and the corresponding pore volumes, and finally calculating the total content of the free oil in a rock core and the ratio of the total free oil to the total mercury pore volume.
Compared with the prior art, the invention has the following advantages:
the method fully considers the pore distribution size and the corresponding pore volume when calculating the free oil content, calculates the free oil content in each pore by combining the pore distribution rule and the corresponding pore volume, accurately describes the free oil content and the distribution rule in the shale pores, and has stronger reliability and accuracy.
Drawings
The accompanying drawings, which are incorporated in and constitute a part of this specification, are included to provide a further understanding of the invention, and are incorporated in and constitute a part of this specification, illustrate exemplary embodiments of the invention and together with the description serve to explain the invention and not to limit the invention.
FIG. 1 is a flow chart of an embodiment of the method for determining free oil content based on shale pore distribution according to the present invention;
FIG. 2 is a graph of the mass fraction of hydrocarbon components of crude shale oil in accordance with an embodiment of the present invention;
FIG. 3 is a graph of pore size distribution frequency for a shale sample in accordance with an embodiment of the present invention;
FIG. 4 is a graph of pore volumes corresponding to pore sizes of shale in accordance with an embodiment of the present invention;
FIG. 5 is a graph showing the mass density distribution of hydrocarbon molecules between organic pore walls in an embodiment of the present invention;
FIG. 6 is a graph of the ratio of free oil in pore volume for different pore sizes in an embodiment of the present invention;
FIG. 7 is a graph of free oil content at different pore radii in the shale sample in accordance with an embodiment of the present invention;
Detailed Description
It is to be understood that the following detailed description is exemplary and is intended to provide further explanation of the invention as claimed. Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention belongs.
It is noted that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of exemplary embodiments according to the invention. As used herein, the singular forms "a", "an" and "the" are intended to include the plural forms as well, and it should be understood that when the terms "comprises" and/or "comprising" are used in this specification, they specify the presence of the stated features, steps, operations, and/or combinations thereof, unless the context clearly indicates otherwise.
In order to make the technical solutions of the present invention more clearly understood by those skilled in the art, the technical solutions of the present invention will be described in detail below with reference to specific embodiments.
Example 1
As shown in fig. 1, the method for determining the free oil content of the shale pore distribution comprises the following steps:
step 101, selecting shale rock samples of a target block and stratum crude oil samples of the target block.
102, performing a high-pressure mercury injection experiment on the shale rock sample of the target block to obtain shale pore size distribution and pore volumes corresponding to the pore sizes. Obtaining rock sample volume V by measuring methodbObtaining the volume V of rock sample particles by a helium hole methodgAnd subtracting the particle volume from the rock sample volume to obtain a rock sample pore volume Vp(ii) a Weighing the mass m of the rock sample by using a balance, and mixing m with VpInputting the mercury into a mercury intrusion test system to perform a high-pressure mercury intrusion test. Obtaining the radius R of the pore space according to the experimental result of high-pressure mercury injectioniAnd a pore radius RiCorresponding pore volume key parameters
103, carrying out hydrocarbon full-component analysis on the stratum crude oil sample of the target block to obtain the mass fraction of hydrocarbon components.
Through a single degassing experiment, the mass fraction of each hydrocarbon component is obtained, and the calculation formula is as follows:
in the formula, XfiIs the mole fraction of the i component of the formation fluid; wdIs the mass value of dead oil, g;
is the value of the average relative molar mass of the dead oil, g/mol; x is the number ofiIs the mole fraction of the dead oil i component; r is a molar gas constant of 8.3145MPa cm3/(mol·K)；yiThe mole fraction of gas i component, in dimensionless units, is evolved for a single degassing.
And step 104, combining a molecular dynamics simulation method to obtain the thickness and the characteristics of the organic pore adsorption layer under the crude oil.
Setting fluid composition according to the mass fraction of hydrocarbon components of shale oil, controlling the temperature of the whole molecular simulation system to be the oil reservoir temperature by adopting a Nose-Hoover algorithm based on a LAMMPS molecular simulation program, simulating under the conditions of fixed molecular number, fixed volume and fixed temperature to balance the system, and determining that the molecular simulation system reaches a balanced state when the parameters of the total energy, the temperature, the pressure and the like of the system do not change along with time to obtain the mass density distribution map of the organic pore adsorption layer and the thickness Ra of the adsorption layer under the reservoir crude oil.
105, calculating the volume ratio of the separated oil at different apertures, wherein the calculation formula is as follows:
wherein,
is a radius RiThe ratio of the pore diameter free oil to the pore volume, decimal fraction; ri is the pore radius, nm; ra is the thickness of the adsorption layer, nm; l is the characteristic length of the rock sample，cm。
106, calculating the free oil content of the shale sample in pore size distribution, wherein the calculation formula is as follows:
in the formula,
is a radius RiPore diameter of (2) free oil volume, cm3；
Is a radius RiPore size of (d), cm3。
Step 107, calculating the total volume of free oil of the core sample, wherein the calculation formula is as follows: the calculation formula of the total volume of the free oil of the core sample is as follows:
108, calculating the total pore volume of mercury in the rock sample and the proportion of total free oil in the total pore volume according to the following formula:
wherein, VfIs the volume of total free oil in the rock sample, cm3；VpHgIs the total pore volume, cm, of the rock sample into which mercury enters3(ii) a Alpha is the ratio of the total free oil content of the sample to the total mercury pore volume.
Example 2
The method for measuring the free oil content of the shale pore distribution comprises the following steps:
Obtaining rock sample volume V by measuring methodbObtaining the volume V of rock sample particles by a helium hole methodgAnd subtracting the particle volume from the rock sample volume to obtain a rock sample pore volume Vp；
And 2, performing a high-pressure mercury injection experiment on the shale rock sample of the target block to obtain the shale pore size distribution and the pore volume corresponding to each pore size. Obtaining rock sample volume V by measuring methodbObtaining the volume V of rock sample particles by a helium hole methodgAnd subtracting the particle volume from the rock sample volume to obtain a rock sample pore volume Vp(ii) a Weighing the mass m of the rock sample by using a balance, and mixing m with VpInputting the mercury into a mercury intrusion test system to perform a high-pressure mercury intrusion test. Obtaining the radius R of the pore space according to the experimental result of high-pressure mercury injectioniAnd a pore radius RiCorresponding pore volume key parameters
And (3) carrying out data processing on the high-pressure mercury intrusion experiment result to obtain a shale pore size distribution frequency diagram, such as a pore volume diagram corresponding to the shale pore size shown in fig. 3, and a pore volume diagram corresponding to the shale pore size shown in fig. 4.
And 3, carrying out hydrocarbon full-component analysis on the stratum crude oil sample of the target block to obtain the mass fraction of hydrocarbon components.
Through a single degassing experiment, the mass fraction of each hydrocarbon component is obtained, and the calculation formula is as follows:
in the formula, XfiIs the mole fraction of the i component of the formation fluid; wdIs the mass value of dead oil, g;
is the value of the average relative molar mass of the dead oil, g/mol; x is the number ofiIs the mole fraction of the dead oil i component; r is moleGas constant, 8.3145MPa cm3/(mol·K)；yiThe mole fraction of gas i component, in dimensionless units, is evolved for a single degassing.
A mass fraction distribution map of the hydrocarbon component was obtained as shown in fig. 2.
And 4, combining a molecular dynamics simulation method to obtain the thickness and the characteristics of the organic pore adsorption layer under the crude oil.
Setting fluid parameters according to the mass fraction of hydrocarbon components of the shale oil, and setting the fluid component to be CH4、C2H6、C3H8、C4H10、C5H12、C6H14、C7H16、C13H28Wherein the component higher than C7 is C13H28Replacing, using graphene to replace organic matters in the shale reservoir, based on a LAMMPS molecular simulation program, adopting a No é -Hoover algorithm to control the temperature of the whole molecular simulation system to be the reservoir temperature, simulating 1000ps under the conditions of fixed molecular number and fixed volume and temperature (NVT ensemble) to balance the system, and when parameters such as total energy, temperature and pressure of the system do not change along with time, determining that the molecular simulation system reaches a balanced state, and obtaining a mass density distribution diagram of an organic pore adsorption layer and an adsorption layer thickness Ra under the reservoir crude oil, as shown in FIG. 5.
And 5, calculating the ratio of the free oil under different pore diameters in the corresponding pore volume according to the thickness Ra of the adsorption layer obtained by the molecular simulation technology:
in the formula,
is a radius RiThe ratio of the pore diameter free oil to the pore volume, decimal fraction; ri is the pore radius, nm; ra is the thickness of the adsorption layer, nm; l is the characteristic length of the rock sample, cm. The results are shown in FIG. 6.
Step 6, obtaining pore volumes V corresponding to different pore diameters according to mercury intrusion experimentsRiObtaining the free oil content V of the shale sample in the pore size distributionfRiAnd establishing a pore volume and free oil volume distribution diagram under different pore size scales, as shown in fig. 7:
in the formula,
is a radius RiPore diameter of (2) free oil volume, cm3；
Is a radius RiPore size of (d), cm3。
And 7, calculating the total volume of the free oil of the rock core sample according to the following calculation formula:
and 8, calculating the total pore volume of mercury in the rock sample and the proportion of total free oil in the total pore volume according to the following formula:
wherein, VfIs the volume of total free oil in the rock sample, cm3；VpHgIs the total pore volume, cm, of the rock sample into which mercury enters3(ii) a Alpha is the ratio of the total free oil content of the sample to the total mercury pore volume.
Example 3
The method described in example 2 was usedThe method is used for measuring the content of free oil in the pore distribution of the shale in a certain block, and the total mercury volume of the obtained shale sample is 0.0867cm3The total free oil volume was 0.0366cm3Wherein the free oil content of the shale sample is 42.21%, and the volume of free oil in each pore is shown in table 1.
Table 1 shale pore size free oil content scale
The above embodiments are preferred embodiments of the present invention, but the present invention is not limited to the above embodiments, and any other changes, modifications, substitutions, combinations, and simplifications which do not depart from the spirit and principle of the present invention should be construed as equivalents thereof, and all such modifications are intended to be included in the scope of the present invention.
Claims (10)
1. A method for determining free oil content based on shale pore distribution, which is characterized by comprising the following steps: selecting a shale rock sample of a target block, and performing a high-pressure mercury injection experiment; obtaining the pore size distribution of the shale and the pore volume corresponding to each pore size; selecting a stratum crude oil sample of a target block, and performing hydrocarbon full-component analysis to obtain a hydrocarbon component mass fraction; combining a molecular dynamics simulation method to obtain the thickness and the characteristics of the organic pore adsorption layer under the crude oil; calculating the volume ratio of separated oil at different apertures; calculating the free oil content of the shale sample in pore size distribution; and calculating the total volume of the free oil of the core sample and the proportion of the total free oil in the total pore volume.
2. The method as claimed in claim 1, wherein the shale rock sample of the target block is selected, and the volume V of the rock sample is obtained by measurementbObtaining rock sample particles by using a helium hole methodProduct VgAnd subtracting the particle volume from the rock sample volume to obtain a rock sample pore volume Vp(ii) a Weighing the mass m of the rock sample by using a balance, and mixing m with VpInputting the mercury into a mercury intrusion test system to perform a high-pressure mercury intrusion test.
3. The method according to claim 2, wherein the pore radius R is obtained from the result of the high-pressure mercury intrusion testiAnd a pore radius RiCorresponding pore volume key parameter
4. The method of claim 1, wherein the mass fraction of each hydrocarbon component is obtained by performing a single degassing experiment on the formation crude oil in the target zone according to the formula:
in the formula, XfiIs the mole fraction of the i component of the formation fluid; wdIs the mass value of dead oil, g;
is the value of the average relative molar mass of the dead oil, g/mol; x is the number ofiIs the mole fraction of the dead oil i component; r is a molar gas constant of 8.3145MPa cm3/(mol·K)；yiThe mole fraction of gas i component, in dimensionless units, is evolved for a single degassing.
5. The determination method according to claim 1, characterized in that the fluid composition is set according to the mass fraction of hydrocarbon components of shale oil, based on LAMMPS molecular simulation program, the Nose-Hoover algorithm is adopted to control the temperature of the whole molecular simulation system to be the reservoir temperature, the simulation is carried out under the conditions of fixed molecular number and fixed volume and fixed temperature, the system is balanced, when the parameters of the system such as total energy, temperature and pressure do not change with time, the molecular simulation system is determined to reach the balanced state, and the mass density distribution map of the organic pore adsorption layer under the reservoir crude oil and the thickness Ra of the adsorption layer are obtained.
6. The method according to claim 5, wherein the fluid composition is CH4、C2H6、C3H8、C4H10、C5H12、C6H14、C7H16、C13H28Wherein the component higher than C7 is C13H28Instead, graphene is used to replace organic matter in shale reservoirs.
7. The method according to claim 1, wherein the calculation formula of the volume ratio of the separated oil at different pore diameters is as follows:
wherein alpha isRiIs a radius RiThe ratio of the pore diameter free oil to the pore volume, decimal fraction; ri is the pore radius, nm; ra is the thickness of the adsorption layer, nm; l is the characteristic length of the rock sample, cm.
8. The method of claim 1, wherein the free oil content of the shale sample in the pore size distribution is calculated by the formula:
in the formula,
is a radius RiPore diameter of (2) free oil volume, cm3；
Is a radius RiPore size of (d), cm3。
9. The method as claimed in claim 1, wherein the total volume of free oil in the core sample is calculated as follows:
wherein, VfIs the volume of total free oil in the rock sample, cm3。
10. The method of claim 9, wherein the total pore volume into which mercury enters the rock sample and the ratio of the total free oil to the total pore volume are calculated as follows:
wherein, VfIs the volume of total free oil in the rock sample, cm3；VpHgIs the total pore volume, cm, of the rock sample into which mercury enters3(ii) a Alpha is the ratio of the total free oil content of the sample to the total mercury pore volume.
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| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
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