CN106837318B - Method and device for obtaining rock stratum thick oil content - Google Patents
Method and device for obtaining rock stratum thick oil content Download PDFInfo
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- 239000011435 rock Substances 0.000 title claims abstract description 193
- 238000000034 method Methods 0.000 title claims abstract description 67
- 238000001228 spectrum Methods 0.000 claims abstract description 243
- 239000012530 fluid Substances 0.000 claims abstract description 180
- 230000015572 biosynthetic process Effects 0.000 claims abstract description 151
- 238000005755 formation reaction Methods 0.000 claims abstract description 151
- 229920006395 saturated elastomer Polymers 0.000 claims abstract description 101
- 239000008398 formation water Substances 0.000 claims abstract description 95
- 239000003921 oil Substances 0.000 claims abstract description 91
- 239000000295 fuel oil Substances 0.000 claims abstract description 40
- 238000005119 centrifugation Methods 0.000 claims abstract description 18
- 238000005259 measurement Methods 0.000 claims description 22
- 238000012545 processing Methods 0.000 claims description 12
- 238000012937 correction Methods 0.000 claims description 11
- 101001123678 Homo sapiens Phenylethanolamine N-methyltransferase Proteins 0.000 claims description 6
- 102100024611 Phosphatidylethanolamine N-methyltransferase Human genes 0.000 claims description 6
- 238000012986 modification Methods 0.000 claims description 5
- 230000004048 modification Effects 0.000 claims description 5
- 230000003595 spectral effect Effects 0.000 claims description 5
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 4
- 239000011148 porous material Substances 0.000 description 10
- 238000005481 NMR spectroscopy Methods 0.000 description 7
- 238000010586 diagram Methods 0.000 description 7
- 230000000694 effects Effects 0.000 description 4
- 238000012795 verification Methods 0.000 description 4
- 238000002073 fluorescence micrograph Methods 0.000 description 2
- 238000003860 storage Methods 0.000 description 2
- 239000000126 substance Substances 0.000 description 2
- 238000004364 calculation method Methods 0.000 description 1
- 239000000084 colloidal system Substances 0.000 description 1
- 239000003086 colorant Substances 0.000 description 1
- 239000010779 crude oil Substances 0.000 description 1
- 238000005516 engineering process Methods 0.000 description 1
- 238000011156 evaluation Methods 0.000 description 1
- 238000002474 experimental method Methods 0.000 description 1
- 230000008014 freezing Effects 0.000 description 1
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- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
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Abstract
The invention provides a method and a device for obtaining the thick oil content of a rock stratum. The method for obtaining the thick oil content of the rock stratum provided by the invention comprises the following steps: according to the first T of a plurality of core samples under the condition of saturated formation water2Spectra and a second T of the plurality of core samples under centrifugation2Spectrum, obtaining a functional relation among the porosity of the bound fluid, the porosity of the mobile fluid and the total porosity when the rock stratum is under the condition of saturated formation water; the plurality of core samples are core samples taken from rock formations at different depths; third T of rock formation according to actual measured first depth2Spectrum, third T2T of the spectrum2And determining the heavy oil content of the rock stratum at the first depth by the cut-off value and the functional relation. The method and the device for obtaining the thick oil content of the rock stratum can obtain the thick oil content of rock strata at different depths, and are low in cost.
Description
Technical Field
The invention relates to a nuclear magnetic resonance logging technology, in particular to a method and a device for obtaining rock stratum thick oil content.
Background
The thickened oil is crude oil with high content of asphaltene and colloid and high viscosity. Because thick oil has special high viscosity and high freezing point characteristics, the thick oil has poor mobility in rock formations and mineshafts, and further brings a plurality of problems to the exploitation of the rock formations rich in the thick oil, for example, for the rock formations rich in the thick oil, a high-investment tertiary oil recovery process method must be adopted. Therefore, the research on the heavy oil content of the rock stratum has very important significance for guiding the exploitation of the rock stratum.
At present, a fluorescent thin slice method is often adopted to evaluate the heavy oil content of the rock formation. Specifically, because different substances in the rock stratum show different colors under fluorescence, the thick oil content of the rock stratum sample can be determined by utilizing the fluorescence image of the rock stratum sample. However, since the method is a laboratory method, the heavy oil content of the rock formation can be determined only according to the fluorescence image of the rock formation sample, and then the production practice can be guided according to the heavy oil content of the rock formation sample. Therefore, when the method is used for determining the thick oil content of rock formations with different depths, on one hand, core samples of the rock formations with different depths need to be obtained, and the cost is high; on the other hand, since a rock formation of some depth is not easy to obtain a core sample, the thick oil content of the rock formation of some depth cannot be determined by the above method.
Disclosure of Invention
The invention provides a method and a device for obtaining thick oil content of a rock stratum, which can obtain the thick oil content of rock strata at different depths and have lower cost.
The invention provides a method for acquiring the thick oil content of a rock stratum, which comprises the following steps:
according to the first T of a plurality of core samples under the condition of saturated formation water2Spectra and a second T of the plurality of core samples under centrifugation2Spectrum, obtaining a functional relation among the porosity of the bound fluid, the porosity of the mobile fluid and the total porosity when the rock stratum is under the condition of saturated formation water; the plurality of core samples are core samples taken from rock formations at different depths;
third T of rock formation according to actual measured first depth2Spectrum, the third T2T of the spectrum2And determining the heavy oil content of the rock stratum at the first depth by the cut-off value and the functional relation.
Further, the first T under saturated formation water conditions according to the plurality of core samples2Spectra and a second T of the plurality of core samples under centrifugation2The spectrum is used for acquiring a functional relation among the porosity of the bound fluid, the porosity of the mobile fluid and the total porosity of the rock stratum under the condition of saturated formation water, and specifically comprises the following steps:
first T according to each core sample2Spectra and second T of each of said core samples2Spectrum, determining the first T of each core sample2T of the spectrum2A cutoff value;
according to the first T of each core sample2Spectra and first T of each of said core samples2T of the spectrum2A cutoff value, wherein the bound fluid porosity of each core sample under the saturated formation water condition, the mobile fluid porosity of each core sample under the saturated formation water condition and the total porosity of each core sample under the saturated formation water condition are obtained;
and determining the functional relation according to the bound fluid porosity of each core sample under the saturated formation water condition, the movable fluid porosity of each core sample under the saturated formation water condition and the total porosity of each core sample under the saturated formation water condition.
Further, the third T of the rock formation at the first depth according to the actual measurement2Spectrum, the third T2T of the spectrum2Determining the heavy oil content of the rock formation at the first depth by using the cutoff value and the functional relation, specifically comprising:
a third T of the rock formation according to the actually measured first depth2Spectrum, the third T2T of the spectrum2A cutoff value determines a first bound fluid porosity of the formation at the first depth and a first mobile fluid porosity of the formation at the first depth;
determining a second bound fluid porosity of the formation at the first depth under saturated formation water conditions based on the first mobile fluid porosity and the functional relationship;
determining a heavy oil content of the formation at the first depth based on the first and second irreducible fluid porosities.
Further, determining the heavy oil content of the rock formation at the first depth according to the first bound fluid porosity and the second bound fluid porosity specifically includes:
determining T from a ratio of the second bound fluid porosity to the first bound fluid porosity2A spectral modification factor;
according to the T2Spectral correction factor and the third T2Spectrum to obtain the fourth T2A spectrum; wherein the third T2T of the spectrum2A cutoff value and said fourth T2T of the spectrum2The cut-off values are equal;
according to the third T2Spectrum and said fourth T2And (5) performing spectrum to obtain the heavy oil content of the rock stratum at the first depth.
Further, the functional relation is PBVI ═ a × PNMT ∈ eb*PM(ii) a Wherein the PBVI isBound fluid porosity; the PNMT is total porosity; the PM is mobile fluid porosity; both a and b are constants.
Further, the first T under saturated formation water conditions according to the plurality of core samples2Spectra and a second T of the plurality of core samples under centrifugation2Before obtaining a functional relationship among the bound fluid porosity, mobile fluid porosity and total porosity of the rock formation under saturated formation water conditions, the method further comprises:
obtaining a first T of the plurality of core samples under a saturated formation water condition2Spectra and a second T of the plurality of core samples under centrifugation2Spectra.
Further, the third T of the rock formation at the first depth according to the actual measurement2Spectrum, the third T2T of the spectrum2Before determining the heavy oil content of the formation at the first depth using the cutoff value and the functional relation, the method further comprises:
obtaining a third T of the actually measured rock formation at the first depth2Spectra.
The second aspect of the present invention provides a device for obtaining thick oil content in a rock formation, comprising: an acquisition module and a processing module, wherein,
the acquisition module is used for acquiring a first T of a plurality of core samples under a saturated formation water condition2Spectra and a second T of the plurality of core samples under centrifugation2Spectrum, obtaining a functional relation among the porosity of the bound fluid, the porosity of the mobile fluid and the total porosity when the rock stratum is under the condition of saturated formation water; wherein the plurality of core samples are core samples taken from rock formations at different depths;
the processing module is used for measuring a third T of the rock stratum at the first depth according to actual measurement2Spectrum, the third T2T of the spectrum2And determining the heavy oil content of the rock stratum at the first depth by the cut-off value and the functional relation.
Further, the obtaining module is specifically configured to obtain a core sample for each core sampleFirst T of article2Spectra and second T of each of said core samples2Spectrum, determining the first T of each core sample2T of the spectrum2Cutoff value according to first T of each core sample2Spectra and first T of each of said core samples2T of the spectrum2And determining the functional relation according to the bound fluid porosity of each core sample under the saturated formation water condition, the movable fluid porosity of each core sample under the saturated formation water condition and the total porosity of each core sample under the saturated formation water condition.
Further, the processing module is specifically configured to determine a third T of the rock formation at the first depth based on the actual measurement2Spectrum, the third T2T of the spectrum2The cutoff value determines a first bound fluid porosity of the formation at the first depth and a first mobile fluid porosity of the formation at the first depth, and determines a second bound fluid porosity of the formation at the first depth under saturated formation water conditions based on the first mobile fluid porosity and the functional relationship, and determines a heavy oil content of the formation at the first depth based on the first bound fluid porosity and the second bound fluid porosity.
Further, the processing module is further specifically configured to determine T from a ratio of the second bound fluid porosity to the first bound fluid porosity2Spectral correction factor and based on said T2Spectral correction factor and the third T2Spectrum to obtain the fourth T2Spectrum, and according to said third T2Spectrum and said fourth T2Spectrum to obtain the heavy oil content of the rock stratum of the first depth, wherein the third T2T of the spectrum2A cutoff value and said fourth T2T of the spectrum2The cut-off values are equal.
Further, the device for obtaining the thick oil content of the rock stratum provided by the invention further comprises: a first measurement template, wherein the first measurement module is used for obtaining a first T of the plurality of core samples under the saturated formation water condition2Spectra and a second T of the plurality of core samples under centrifugation2Spectra.
Further, the device for obtaining the thick oil content of the rock stratum provided by the invention further comprises: a second measurement module, wherein the second measurement module is used for acquiring a third T of the rock formation at the first depth of the actual measurement2Spectra.
The invention provides a method and a device for obtaining rock stratum thick oil content2Spectrum and second T of the plurality of core samples in centrifugal state2Spectrum, obtaining the function relation among the porosity of the binding fluid, the porosity of the mobile fluid and the total porosity when the rock stratum is under the condition of saturated formation water, and further according to the actually measured third T of the rock stratum with the first depth2Spectrum, the third T2T of the spectrum2And determining the heavy oil content of the formation at the first depth by the cut-off value and the functional relation. Therefore, when the thick oil content of rock formations with different depths is required to be obtained, the rock formations with each depth do not need to be sampled, the functional relation among the porosity of the binding fluid, the porosity of the movable fluid and the total porosity of the rock formations under the condition of saturated formation water is determined according to a plurality of core samples (rock formation samples taken from rock formations with several depths), and then the third T of the rock formations with each depth is measured2The spectrum may be based on the functional relationship and the third T of the formation at each depth2Spectrum and the third T2T of the spectrum2The cut-off value is obtained to the thick oil content of the rock stratum of each depth, so that when the thick oil content of the rock stratum of a certain depth needs to be obtained, a rock core sample of the rock stratum of the certain depth does not need to be obtained, the cost can be saved, meanwhile, the problem that the thick oil content of the rock stratum of the certain depth cannot be determined due to the fact that the rock core sample of the rock stratum of the certain depth cannot be obtained by the method in the prior art can be avoided,the heavy oil content of the formation at all depths can be obtained.
Drawings
In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings needed to be used in the description of the embodiments or the prior art will be briefly introduced below, and it is obvious that the drawings in the following description are some embodiments of the present invention, and for those skilled in the art, other drawings can be obtained according to these drawings without creative efforts.
Fig. 1 is a flowchart of a method for obtaining a thick oil content of a formation according to an embodiment of the present invention;
FIG. 2 is the first T of a core sample under saturated formation water conditions2A schematic representation of a spectrum;
FIG. 3 is a schematic diagram of a relationship curve obtained by a least squares fit method;
FIG. 4 is a third T of the formation at the first depth actually measured2A schematic representation of a spectrum;
fig. 5 is a schematic diagram of a verification result of effect verification performed on the thickened oil content obtaining method provided by the present invention;
FIG. 6 is a flowchart of a method for obtaining thick oil content of a formation according to a second embodiment of the present invention;
FIG. 7 is a fourth T constructed by the method for obtaining thick oil content of rock formation according to the second embodiment of the present invention2A schematic representation of a spectrum;
FIG. 8 is a graph according to a third T2Spectrum and fourth T2A schematic of the spectrally determined difference spectrum;
fig. 9 is a schematic structural diagram of a thick oil content obtaining apparatus for a rock formation according to a third embodiment of the present invention;
fig. 10 is a schematic structural diagram of a thick oil content obtaining apparatus for a rock formation according to a fourth embodiment of the present invention.
Detailed Description
In order to make the objects, technical solutions and advantages of the embodiments of the present invention clearer, the technical solutions in the embodiments of the present invention will be clearly and completely described below with reference to the drawings in the embodiments of the present invention, and it is obvious that the described embodiments are some, but not all, embodiments of the present invention. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present invention.
The invention provides a method and a device for obtaining thick oil content of a rock stratum, which can obtain the thick oil content of rock strata at different depths and have lower cost.
The method and the device for obtaining the rock stratum thick oil content can be applied to the field of rock stratum thick oil evaluation, and specifically can be applied to obtaining the thick oil content of rock strata at different depths.
Fig. 1 is a flowchart of a method for obtaining a thick oil content of a formation according to an embodiment of the present invention. This example relates to a specific method for obtaining the thick oil content of the rock formation. The execution main body of the embodiment can be a separate rock stratum thick oil content acquisition device, and can also be other equipment integrated with the rock stratum thick oil content acquisition device. The embodiment is described by taking the execution subject as other equipment integrated with the rock thick oil content acquisition device as an example. As shown in fig. 1, the method for obtaining the thick oil content of the formation according to this embodiment may include the following steps:
s101, according to the first T of a plurality of core samples under the condition of saturated formation water2Spectrum and second T of the plurality of core samples in centrifugal state2Spectrum, obtaining a functional relation among the porosity of the bound fluid, the porosity of the mobile fluid and the total porosity when the rock stratum is under the condition of saturated formation water; the plurality of core samples are core samples taken from formations at different depths.
Specifically, in this embodiment, the plurality of core samples are specifically 37 core samples, and in addition, the 37 core samples are core samples taken from rock formations at different depths of the reservoir area to be evaluated, and lithology and pore structure of the 37 core samples are different.
Note that each core sample has a first T at saturated formation water conditions2Spectra and plurality of core samples as described aboveSecond T of the product in centrifugal state2Spectra were acquired under laboratory conditions.
The first T under saturated formation water conditions based on a plurality of core samples is described in detail below2Spectra and a second T of the plurality of core samples under centrifugation2And (3) spectrum, namely obtaining a specific step of binding a functional relation among the fluid porosity, the mobile fluid porosity and the total porosity when the rock stratum is under the saturated stratum water condition. Specifically, the functional relationship among the bound fluid porosity, mobile fluid porosity and total porosity of the rock formation under saturated formation water conditions can be obtained as follows:
the method comprises the following steps: first T according to each core sample2Spectra and second T for each of the above core samples2Spectrum, determining the first T of each of the above core samples2T of the spectrum2A cutoff value.
In particular, at T2Presence of a T in the spectrum2Cutoff when relaxation time of pore fluid is less than T2At the cut-off value, the pore fluid is the confining fluid; when the relaxation time of the pore fluid is greater than T2At the cut-off value, the pore fluid is mobile. In this step, the first T of each core sample needs to be determined2T of the spectrum2Cutoff value according to first T2T of the spectrum2The cut-off value determines the first T2The type of pores on the spectrum.
In particular, the first T of a core sample may be determined2Spectra and second T of this core sample2Spectrum, determining the first T of the core sample2T of the spectrum2A cutoff value. First T how to sample a core2Spectra and second T of this core sample2Spectrum, determining the first T of the core sample2T of the spectrum2The specific method of the cutoff value can be referred to the description in the prior art, and is not described herein.
Step two, according to the first T of each core sample2Spectra and first T of each core sample2T of the spectrum2Cutoff value, obtaining each core sampleA bound fluid porosity under saturated formation water conditions, a mobile fluid porosity under saturated formation water conditions for each core sample, and a total porosity under saturated formation water conditions for each core sample.
Specifically, FIG. 2 shows the first T of a core sample under saturated water conditions2Spectra. Please refer to fig. 2 (wherein, T in fig. 22cutoff denotes the first T2T of the spectrum2Cutoff value) when determining the first T of each core sample2T of the spectrum2Cutoff value, at this time, first T for each core sample2Spectrum, according to the first T of each core sample2T of the spectrum2Determining the first T of each core sample by a cutoff value2The type of pores on the spectrum. Specifically, referring to the description in step one, in conjunction with fig. 2, the first T2T on the spectrum2Cutoff value will be first T2The spectrum is divided into two parts, where less than T2The fraction of the cut-off value is the bound fluid porosity, greater than T2The fraction of the cutoff is the mobile fluid porosity. When the first T of each core sample was determined2After the pore type on the spectrum, at this time, the bound fluid porosity of each core sample under the saturated formation water condition, the mobile fluid porosity of each core sample under the saturated formation water condition, and the total porosity of each core sample under the saturated formation water condition can be calculated according to an integral method. Specifically, for how to calculate the bound fluid porosity of each core sample under the saturated formation water condition, the mobile fluid porosity of each core sample under the saturated formation water condition, and the total porosity of each core sample under the saturated formation water condition by using an integration method, reference may be made to the description in the prior art, and details are not repeated here.
In this example, with reference to the above example, after this step, 37 sets of data are obtained, where each set of data includes the bound fluid porosity of a core sample under saturated formation water conditions, the mobile fluid porosity of the core sample under saturated formation water conditions, and the total porosity of the core sample.
And step three, determining the functional relation according to the bound fluid porosity of each core sample under the saturated formation water condition, the movable fluid porosity of each core sample under the saturated formation water condition and the total porosity of each core sample under the saturated formation water condition.
Specifically, in this step, the functional relationship among the bound fluid porosity, mobile fluid porosity and total porosity of the rock formation under saturated formation water conditions is obtained as follows: specifically, after obtaining the bound fluid porosity of each core sample under the saturated formation water condition, the movable fluid porosity of each core sample under the saturated formation water condition, and the total porosity of each core sample under the saturated formation water condition through the second step, then, for one core sample, the movable fluid porosity of the core sample under the saturated formation water condition is taken as an abscissa, and a ratio of the bound fluid porosity of the core sample under the saturated formation water condition to the total porosity of the core sample under the saturated formation water condition is taken as an ordinate to plot points, in this embodiment, after performing the same processing on 37 sets of data of 37 core samples, 37 points may be obtained under the same coordinate system, as shown in fig. 3, at this time, the 37 points are fitted by using a least squares fitting method to obtain a fitting curve of the 37 points, the functional relation of the fitting curve is the functional relation among the porosity of the bound fluid, the porosity of the mobile fluid and the total porosity of the rock stratum under the condition of saturated formation water. It should be noted that, for a detailed description of the least square fitting method, reference may be made to the description in the prior art, and details are not described here.
For example, in this embodiment, the functional relation of the fitting curve is: 0.8446e-0.1251xThe function relation among the porosity of the bound fluid, the porosity of the mobile fluid and the total porosity of the rock stratum under the condition of saturated formation water is obtained as PBVI (a PNMT) eb*PMWhere PBVI is bound fluid porosity, PNMT is total porosity, PM is mobile fluid porosity, a, b are constants, and in this embodiment, a is 0.8446 and b is-0.125. This is achieved byIn addition, as can be seen from fig. 3, the correlation coefficient of the fitted curve is 0.9314, which shows that the functional relation of the fitted curve can accurately reflect the correlation among the bound fluid porosity, the mobile fluid porosity and the total porosity of the rock formation under the saturated formation water condition.
It should be noted that, for different reservoir blocks to be evaluated, the values of the constants a and b are different.
S102, according to the actually measured third T of the rock stratum with the first depth2Spectrum, the third T2T of the spectrum2And determining the heavy oil content of the rock stratum at the first depth by the cut-off value and the functional relation.
Specifically, the third T of the rock formation of the first depth is actually measured2Spectra are acquired from in situ nuclear magnetic resonance measurements of the formation at a first depth. In addition, the third T2T of the spectrum2The method for determining the cutoff value can be described in the prior art, and is not described herein. For example, let a third T2T of the spectrum2The cutoff value is equal to the first T of each core sample in step S1012T of the spectrum2Average of the cut-off values (in this example, the third T of the formation at the first depth actually measured2T of the spectrum2Cutoff is equal to the 37 first Ts mentioned above2T of the spectrum2Average of cutoff values).
A detailed description of how to determine the third T of the rock formation at the first depth based on actual measurements is provided below2Spectrum, the third T2T of the spectrum2And determining the heavy oil content of the rock stratum at the first depth according to the cutoff value and the functional relation. Specifically, the method can comprise the following steps:
step one, according to the actually measured third T of the rock stratum with the first depth2Spectrum, the third T2T of the spectrum2The cutoff value determines a first bound fluid porosity of the formation at the first depth and a first mobile fluid porosity of the formation at the first depth.
Specifically, FIG. 4 shows a third T of the formation at the first depth as actually measured2Spectra. Please refer to fig. 4, the third T2T of the spectrum2Cutoff value will likewise be the third T2The spectrum is divided into two parts, less than T2The fraction of the cut-off value is the bound fluid porosity, greater than T2The fraction of the cutoff is the mobile fluid porosity. Similarly, in this step, the third T of the formation at the first depth is measured according to the actual measurement2Spectrum, the third T2T of the spectrum2The cutoff value may be integrated to determine a first restriction fluid porosity of the formation at the first depth and a first mobilizable fluid porosity of the formation at the first depth.
It should be noted that the first bound fluid porosity of the formation at the first depth is the bound fluid porosity of the formation at the first depth in the actual state. In addition, when the stratum contains thick oil with higher viscosity, T of the thick oil is caused2The relaxation time is so short that the nmr log response signal of the heavy oil tends to overlap with the bound fluid signal.
And secondly, determining the second bound fluid porosity of the rock stratum with the first depth under the condition of saturated formation water according to the first movable fluid porosity and the functional relation.
Specifically, since the heavy oil has no influence on the mobile fluid porosity, at this time, the first mobile fluid porosity of the rock formation at the first depth and the functional relation may be used, that is, the first mobile fluid porosity of the rock formation at the first depth is substituted into the functional relation, and since the total porosity is equal to the sum of the bound fluid porosity and the mobile fluid porosity, the second bound fluid porosity of the rock formation at the first depth under the saturated formation water condition may be calculated. It should be noted that the saturated formation water condition is a hypothetical state where it is assumed that no thick oil exists in the rock formation of the first depth, and thus, according to the description in step S101, when it is assumed that no thick oil exists in the rock formation of the first depth, the bound fluid porosity in the rock formation of the first depth, the mobile fluid porosity in the rock formation of the first depth, and the total porosity in the rock formation of the first depth satisfy the functional relationship system described above, and at this time, actual measurement is usedThird T of2Spectrum and third T2T of the spectrum2The cut-off value allows calculation of a first mobile fluid porosity of the formation at the first depth (mobile fluid porosity of the formation at the first depth in the actual state), and since the heavy oil has no influence on the mobile fluid porosity. Thus, the mobile fluid porosity of the rock formation at the first depth under the saturated water condition is equal to the first mobile fluid porosity, and at this time, the second bound fluid porosity of the rock formation at the first depth under the saturated formation water condition (it is unknown that the rock formation at the first depth does not contain thick oil, and the rock formation at the specific first depth does not contain thick oil) can be obtained by substituting the first mobile fluid porosity into the functional relation.
And step three, determining the thick oil content of the rock stratum of the first depth according to the porosity of the first bound fluid and the porosity of the second bound fluid.
Specifically, the first bound fluid porosity reflects the bound fluid porosity of the rock formation at the first depth in an actual state, and the second bound fluid porosity reflects the bound fluid porosity of the rock formation at the first depth adjusted by saturated formation water, and at this time, the second bound fluid porosity is subtracted from the first bound fluid porosity to obtain the heavy oil content of the rock formation at the first depth.
Fig. 5 is a schematic diagram of a verification result of effect verification performed on the thickened oil content obtaining method provided by the present invention. Specifically, referring to fig. 5, the thick oil content of the core sample at different depths obtained by the fluorescence thin slice method is compared with the thick oil content of the rock formations at different depths obtained by the method provided by the present invention (it should be noted that the core sample at a certain depth is a core sample taken from a rock formation at the same depth), wherein an abscissa of a point in fig. 5 represents the thick oil content of the core sample at a certain depth obtained by the fluorescence thin slice method, and an ordinate represents the thick oil content of the rock formation at the same depth obtained by the method provided by the present invention, as can be seen from fig. 5, a correlation coefficient of a fitting curve of the point in fig. 5 is 0.8539, which is approximately equal to 1, which indicates that by the method provided by the present invention, the thick oil content of the core sample at a different depth can be accurately obtained without the method provided by the present inventionThe thick oil content of the same depth formation. In addition, for the fluorescence thin slice method, if the thick oil content of 50 core samples with different depths is obtained, 50 different core samples need to be obtained from rock strata with different depths of an oil reservoir block to be evaluated, and then the fluorescence thin slice experiment is carried out on the 50 core samples to obtain the thick oil content of the 50 core samples; for the method for obtaining the thick oil content of the rock stratum provided by the invention, if the thick oil content of the rock stratum with different depths of the oil reservoir block to be evaluated is required to be obtained (for example, the thick oil content of the rock stratum with 50 different depths is required to be obtained), at this time, the third T of the rock stratum with 50 different depths is only required to be obtained through the on-site nuclear magnetic logging instrument2Spectrum, and obtaining a plurality of core samples (for example, 37) from rock formations with different depths of a reservoir block to be evaluated, and further obtaining a first T of the plurality of core samples under the condition of saturated formation water2Spectra and second T of the plurality of core samples under centrifugation2And (4) obtaining a functional relation among the porosity of the bound fluid, the porosity of the mobile fluid and the total porosity of the rock stratum under the condition of saturated formation water. Thus, the third T of 50 different depths of rock formation can be determined2The thick oil content of rock formations of 50 different depths is determined through the spectrum and the determined relational expression, 50 rock core samples do not need to be obtained, the cost can be saved, and in addition, the thick oil content of rock formations of some depths cannot be determined through a fluorescence slice method because the rock formations of some depths are not easy to obtain the rock core samples. However, with the method provided by the present disclosure, it is not necessary to obtain core samples for formations at these depths, but only the third T of the formation at these depths2The thick oil content of the rock stratum at the depths can be obtained by the spectrum and the determined functional relation, and the problems existing in the fluorescence slice method are solved.
The invention provides a method and a device for obtaining rock stratum thick oil content2Spectrum and second T of the plurality of core samples in centrifugal state2Spectrum, obtaining the function of the porosity of the binding fluid, the porosity of the mobile fluid and the total porosity of the rock stratum under the condition of saturated formation waterThe numerical relationship, and further based on the actually measured third T of the formation at the first depth2Spectrum, the third T2T of the spectrum2And determining the heavy oil content of the formation at the first depth by the cut-off value and the functional relation. Therefore, when the thick oil content of rock formations with different depths is required to be obtained, the rock formations with each depth do not need to be sampled, the functional relation among the porosity of the binding fluid, the porosity of the movable fluid and the total porosity of the rock formations under the condition of saturated formation water is determined according to a plurality of core samples (rock formation samples taken from rock formations with several depths), and then the third T of the rock formations with each depth is measured2The spectrum can be based on the functional relationship and the third T of the formation for each depth2Spectrum and the third T2T of the spectrum2The cut-off value is obtained to obtain the thick oil content of the rock stratum of each depth, so that when the thick oil content of the rock stratum of a certain depth needs to be obtained, a rock core sample of the rock stratum of the certain depth does not need to be obtained, the cost can be saved, meanwhile, the problem that the thick oil content of the rock stratum of the certain depth cannot be determined due to the fact that the rock core sample of the rock stratum of the certain depth cannot be obtained in the method in the prior art can be avoided, and the thick oil content of the rock stratum of all depths can be obtained.
Optionally, before step S101, the method for obtaining thick oil content of a rock formation provided by this embodiment may further include:
obtaining a first T of a plurality of core samples under a saturated formation water condition2Spectrum and second T of the plurality of core samples in centrifugal state2Spectra.
Specifically, first, a plurality of core samples are taken from rock formations at different depths, for example, in this embodiment, 37 core samples are taken, and the lithology and pore structure of the 37 core samples are different. Then, in a laboratory, measuring the first T of each core sample under the condition of saturated formation water according to the flow specified in 'rock sample nuclear magnetic resonance parameter laboratory measurement specification SY/T6469-2007' standard2Spectra and second T of each core sample described above under centrifugation2Obtaining the second time of each core sample under the condition of saturated formation waterA T2Spectrum and second T of the plurality of core samples in centrifugal state2Spectra. For example, in this example, a first T of 37 core samples under saturated formation water conditions was obtained2Spectrum and second T of the above 37 rock core samples in centrifugation2Spectrum (i.e. 37 first Ts were obtained)2Spectra and 37 second T2Spectral lines).
Optionally, before step S102, the method for obtaining the thick oil content of the rock formation provided by this embodiment may further include:
obtaining a third T of the actually measured rock formation at the first depth2Spectra.
Specifically, the NMR spectrometer may be used to perform NMR measurements on the formation at the first depth to obtain an actual measured third T for the formation at the first depth2Spectra.
Fig. 6 is a flowchart of a method for obtaining the content of heavy oil according to the second embodiment of the present invention. This example relates to a specific method of how to determine the heavy oil content of a formation at a first depth based on a first bound fluid porosity and a second bound fluid porosity. Referring to fig. 6, based on the above embodiment, determining the thick oil content of the formation at the first depth according to the first bound fluid porosity and the second bound fluid porosity may include the following steps:
s201, determining T according to the ratio of the porosity of the second binding fluid to the porosity of the first binding fluid2A spectral modification factor.
In this embodiment, for example, the second fluid porosity is 24% and the first bound fluid porosity is 60%. At this time, T is determined2The spectral correction factor is 2/5.
S202, according to the T2Spectral correction factor and the third T2Spectrum to obtain the fourth T2A spectrum; wherein the third T2T of the spectrum2Cutoff value and the fourth T2T of the spectrum2The cut-off values are equal.
FIG. 7 shows a graph according to T above2Spectral correction factor and the third T2Spectrum, obtained fourth T2Schematic representation of spectra.Specifically, referring to fig. 7, the fourth T is obtained as follows2Spectrum: first, the fourth T2T of the spectrum2Cutoff value and third T2T of the spectrum2The cut-off values are equal; second, the fourth T2T of mobile fluid porosity portion of spectrum2Spectrum and third T2T of mobile fluid porosity portion of spectrum2The spectra are the same; finally, the fourth T2T of bound fluid porosity portion of spectrum2Spectrum equals to the third T2T of the pore part of the bound fluid of the spectrum2T obtained by multiplying spectrum by correction factor2Spectra. (i.e. the
Wherein the content of the first and second substances,is a fourth T2T of bound fluid porosity portion of spectrum2A spectrum; c is T2A spectral modification factor;
is the third T2T of bound fluid porosity portion of spectrum2A spectrum; cutoff is the third T2T of the spectrum2A cutoff value; min is the third T2Initial values of relaxation times on the spectrum; ).
In connection with the above example, in step S201, T is determined2When the spectrum correction factor is 2/5, then in this step, the third T is set2T of bound fluid porosity portion of spectrum2The ordinate of the spectrum was changed to 2/5 to obtain the fourth T2T of bound fluid porosity portion of spectrum2Spectra.
S203, according to the third T2Spectrum and the fourth T2And (5) obtaining the heavy oil content of the rock stratum at the first depth through spectrum.
When the fourth T is obtained2After the spectrum, the fourth T can be calculated by an integral method2Bound fluid porosity of the spectrum. Finally, subtract the fourth T from the first bound fluid porosity2Spectral bound fluid porosity to said first depthHeavy oil content of the formation.
In the method for obtaining the thick oil content of the rock formation, the fourth T is constructed2Spectrum, further according to the third T2Spectrum and fourth T2And (5) performing spectrum to obtain the heavy oil content of the rock stratum at the first depth. Thus, can pass through T2The spectrum visually and clearly shows the heavy oil content of the rock stratum at the first depth.
Further, in order to more intuitively and clearly display the thick oil content of the rock stratum at the first depth through the image, the rock stratum thick oil content obtaining method provided by the invention obtains the fourth T2After the spectrum, the third T can be used2Spectrum and said fourth T2Spectrum to obtain the third T2Spectrum and said fourth T2Difference spectrum of spectrum. FIG. 8 shows a third T2Spectrum and fourth T2FIG. 8 is a schematic diagram of the difference spectrum determined by the spectrum, wherein the third T2Spectrum and fourth T2The difference spectrum of the spectrum reflects the nuclear magnetism T of the thick oil of the rock stratum at the first depth2And the area of the cross axis encircled city and the spectrum, namely the difference spectrum, is the heavy oil content of the rock stratum with the first depth. Thus, the heavy oil content of the rock stratum at the first depth can be visually seen through the differential spectrum.
Fig. 9 is a schematic structural diagram of a thick oil content obtaining apparatus for a rock formation according to a third embodiment of the present invention. The device can be realized by software, hardware or a combination of software and hardware, and can be a single rock stratum thick oil content acquisition device or other equipment integrated with the rock stratum thick oil content acquisition device. As shown in fig. 9, the device for obtaining thick oil content in a rock formation provided by this embodiment includes: an acquisition module 100 and a processing module 200, wherein,
an obtaining module 100 configured to obtain a first T of a plurality of core samples under a saturated formation water condition2Spectra and a second T of the plurality of core samples under centrifugation2Spectrum, obtaining a functional relation among the porosity of the bound fluid, the porosity of the mobile fluid and the total porosity when the rock stratum is under the condition of saturated formation water; wherein the plurality of core samples are core samples taken from rock formations at different depths;
a processing module 200 for determining a third T of the formation at the first depth based on the actual measurements2Spectrum, the third T2T of the spectrum2And determining the heavy oil content of the rock stratum at the first depth by the cut-off value and the functional relation.
The apparatus of this embodiment may be used to implement the technical solution of the method embodiment shown in fig. 1, and the implementation principle and the technical effect are similar, which are not described herein again.
Further, the acquisition module 100 is specifically configured to obtain the first T for each core sample2Spectra and second T of each of said core samples2Spectrum, determining the first T of each core sample2T of the spectrum2Cutoff value according to first T of each core sample2Spectra and first T of each of said core samples2T of the spectrum2And determining the functional relation according to the bound fluid porosity of each core sample under the saturated formation water condition, the movable fluid porosity of each core sample under the saturated formation water condition and the total porosity of each core sample under the saturated formation water condition.
Further, the processing module 200 is specifically configured for determining a third T of the rock formation at the first depth based on the actual measurements2Spectrum, the third T2T of the spectrum2The cutoff value determines a first bound fluid porosity of the formation at the first depth and a first mobile fluid porosity of the formation at the first depth, and determines a second bound fluid porosity of the formation at the first depth under saturated formation water conditions based on the first mobile fluid porosity and the functional relationship, and determines a heavy oil content of the formation at the first depth based on the first bound fluid porosity and the second bound fluid porosity.
Further, the processing module 200And further specifically for determining T from a ratio of the second bound fluid porosity to the first bound fluid porosity2Spectral correction factor and based on said T2Spectral correction factor and the third T2Spectrum to obtain the fourth T2Spectrum, and according to said third T2Spectrum and said fourth T2Spectrum to obtain the heavy oil content of the rock stratum of the first depth, wherein the third T2T of the spectrum2A cutoff value and said fourth T2T of the spectrum2The cut-off values are equal.
The apparatus of this embodiment may be used to implement the technical solution of the method embodiment shown in fig. 6, and the implementation principle and the technical effect are similar, which are not described herein again.
Fig. 10 is a device for obtaining the thick oil content of the rock formation according to the fourth embodiment of the present invention. Referring to fig. 10, on the basis of the foregoing embodiment, the device for obtaining thick oil content in a rock formation provided in this embodiment further includes: a first measurement template 300, wherein the first measurement module 300 is configured to obtain a first T of the plurality of core samples under a saturated formation water condition2Spectra and a second T of the plurality of core samples under centrifugation2Spectra.
Specifically, for example, the first measurement module 300 may be a laboratory nuclear magnetic resonance meter.
Further, the device for obtaining the thick oil content of the rock stratum provided by the invention further comprises: a second measuring module 400, wherein the second measuring module 400 is used for obtaining a third T of the rock formation of the first depth actually measured2Spectra.
Specifically, for example, the second measurement module 400 may be a nuclear magnetic resonance logging tool for use in the field.
Those of ordinary skill in the art will understand that: all or a portion of the steps of implementing the above-described method embodiments may be performed by hardware associated with program instructions. The program may be stored in a computer-readable storage medium. When executed, the program performs steps comprising the method embodiments described above; and the aforementioned storage medium includes: various media that can store program codes, such as ROM, RAM, magnetic or optical disks.
Finally, it should be noted that: the above embodiments are only used to illustrate the technical solution of the present invention, and not to limit the same; while the invention has been described in detail and with reference to the foregoing embodiments, it will be understood by those skilled in the art that: the technical solutions described in the foregoing embodiments may still be modified, or some or all of the technical features may be equivalently replaced; and the modifications or the substitutions do not make the essence of the corresponding technical solutions depart from the scope of the technical solutions of the embodiments of the present invention.
Claims (6)
1. A method for obtaining the thick oil content of a rock stratum is characterized by comprising the following steps:
according to the first T of a plurality of core samples under the condition of saturated formation water2Spectra and a second T of the plurality of core samples under centrifugation2Spectrum, obtaining a functional relation among the porosity of the bound fluid, the porosity of the mobile fluid and the total porosity when the rock stratum is under the condition of saturated formation water; the plurality of core samples are core samples taken from rock formations at different depths;
third T of rock formation according to actual measured first depth2Spectrum, the third T2T of the spectrum2Determining the heavy oil content of the rock stratum at the first depth by using the cutoff value and the functional relation;
the first T under saturated formation water conditions according to the plurality of core samples2Spectra and a second T of the plurality of core samples under centrifugation2The spectrum is used for acquiring a functional relation among the porosity of the bound fluid, the porosity of the mobile fluid and the total porosity of the rock stratum under the condition of saturated formation water, and specifically comprises the following steps:
first T according to each core sample2Spectra and second T of each of said core samples2Spectrum, determining the first T of each core sample2T of the spectrum2A cutoff value;
according to the first T of each core sample2Spectra and first T of each of said core samples2T of the spectrum2Cut-off value, obtainingTaking the bound fluid porosity of each core sample under the saturated formation water condition, the mobile fluid porosity of each core sample under the saturated formation water condition and the total porosity of each core sample under the saturated formation water condition;
determining the functional relation according to the bound fluid porosity of each core sample under the saturated formation water condition, the movable fluid porosity of each core sample under the saturated formation water condition and the total porosity of each core sample under the saturated formation water condition;
the third T of the rock formation according to the actually measured first depth2Spectrum, the third T2T of the spectrum2Determining the heavy oil content of the rock formation at the first depth by using the cutoff value and the functional relation, specifically comprising:
a third T of the rock formation according to the actually measured first depth2Spectrum, the third T2T of the spectrum2A cutoff value determines a first bound fluid porosity of the formation at the first depth and a first mobile fluid porosity of the formation at the first depth;
determining a second bound fluid porosity of the formation at the first depth under saturated formation water conditions based on the first mobile fluid porosity and the functional relationship;
determining a heavy oil content of the formation at the first depth based on the first and second irreducible fluid porosities.
2. The method of claim 1, wherein determining the heavy oil content of the formation at the first depth from the first and second irreducible fluid porosities comprises:
determining T from a ratio of the second bound fluid porosity to the first bound fluid porosity2A spectral modification factor;
according to the T2Spectral correction factor and the third T2Spectrum to obtain the fourth T2A spectrum; wherein the third T2T of the spectrum2A cutoff value and said fourth T2T of the spectrum2The cut-off values are equal;
according to the third T2Spectrum and said fourth T2And (5) performing spectrum to obtain the heavy oil content of the rock stratum at the first depth.
3. The method according to any of claims 1-2, wherein the functional relation is PBVI ═ a PNMT · eb*PM(ii) a Wherein the PBVI is bound fluid porosity; the PNMT is total porosity; the PM is mobile fluid porosity; both a and b are constants.
4. The method of claim 3, wherein the first T under saturated formation water conditions from the plurality of core samples2Spectra and a second T of the plurality of core samples under centrifugation2Before obtaining a functional relationship among the bound fluid porosity, mobile fluid porosity and total porosity of the rock formation under saturated formation water conditions, the method further comprises:
obtaining a first T of the plurality of core samples under a saturated formation water condition2Spectra and a second T of the plurality of core samples under centrifugation2Spectra.
5. The method of claim 4, wherein the third T of the formation at the first depth is based on actual measurements2Spectrum, the third T2T of the spectrum2Before determining the heavy oil content of the formation at the first depth using the cutoff value and the functional relation, the method further comprises:
obtaining a third T of the actually measured rock formation at the first depth2Spectra.
6. A device for obtaining the thick oil content of a rock stratum is characterized by comprising: an acquisition module and a processing module, wherein,
the acquisition module is used for acquiring a plurality of rock core samples in a saturated stratumFirst T under Water2Spectra and a second T of the plurality of core samples under centrifugation2Spectrum, obtaining a functional relation among the porosity of the bound fluid, the porosity of the mobile fluid and the total porosity when the rock stratum is under the condition of saturated formation water; wherein the plurality of core samples are core samples taken from rock formations at different depths;
the processing module is used for measuring a third T of the rock stratum at the first depth according to actual measurement2Spectrum, the third T2T of the spectrum2Determining the heavy oil content of the rock stratum at the first depth by using the cutoff value and the functional relation;
the acquisition module is specifically configured to obtain a first T for each core sample2Spectra and second T of each of said core samples2Spectrum, determining the first T of each core sample2T of the spectrum2Cutoff value according to first T of each core sample2Spectra and first T of each of said core samples2T of the spectrum2A cutoff value, obtaining the bound fluid porosity of each core sample under the saturated formation water condition, the movable fluid porosity of each core sample under the saturated formation water condition and the total porosity of each core sample under the saturated formation water condition, and determining the functional relation according to the bound fluid porosity of each core sample under the saturated formation water condition, the movable fluid porosity of each core sample under the saturated formation water condition and the total porosity of each core sample under the saturated formation water condition;
the processing module is specifically configured to determine a third T of the rock formation at the first depth based on the actual measurement2Spectrum, the third T2T of the spectrum2Determining a first bound fluid porosity of the formation at the first depth and a first mobile fluid porosity of the formation at the first depth based on the cutoff value, determining a second bound fluid porosity of the formation at the first depth under saturated formation water conditions based on the first mobile fluid porosity and the functional relationship, and determining a second bound fluid porosity of the formation at the first depth based on the first bound fluid porosity and the second bound fluid porosityAnd determining the thick oil content of the rock stratum at the first depth.
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