CN114076723A - Quantitative research method for salt-containing shale oil reservoir imbibition - Google Patents
Quantitative research method for salt-containing shale oil reservoir imbibition Download PDFInfo
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- CN114076723A CN114076723A CN202010805453.7A CN202010805453A CN114076723A CN 114076723 A CN114076723 A CN 114076723A CN 202010805453 A CN202010805453 A CN 202010805453A CN 114076723 A CN114076723 A CN 114076723A
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- 238000005213 imbibition Methods 0.000 title claims abstract description 47
- 150000003839 salts Chemical class 0.000 title claims abstract description 36
- 239000003079 shale oil Substances 0.000 title claims abstract description 32
- 238000000034 method Methods 0.000 title claims abstract description 26
- 238000011160 research Methods 0.000 title claims abstract description 15
- 238000001228 spectrum Methods 0.000 claims abstract description 36
- 239000011435 rock Substances 0.000 claims abstract description 33
- XLYOFNOQVPJJNP-ZSJDYOACSA-N Heavy water Chemical compound [2H]O[2H] XLYOFNOQVPJJNP-ZSJDYOACSA-N 0.000 claims abstract description 26
- 238000000605 extraction Methods 0.000 claims abstract description 24
- 238000004090 dissolution Methods 0.000 claims abstract description 18
- 230000033558 biomineral tissue development Effects 0.000 claims abstract description 11
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 9
- 230000035699 permeability Effects 0.000 claims abstract description 8
- 238000004064 recycling Methods 0.000 claims abstract description 4
- 238000005481 NMR spectroscopy Methods 0.000 claims description 10
- 238000012360 testing method Methods 0.000 claims description 8
- 238000001035 drying Methods 0.000 claims description 6
- 230000015572 biosynthetic process Effects 0.000 claims description 5
- 239000003350 kerosene Substances 0.000 claims description 5
- 239000008398 formation water Substances 0.000 claims description 4
- 238000009738 saturating Methods 0.000 claims description 4
- 238000004519 manufacturing process Methods 0.000 claims description 3
- 230000000694 effects Effects 0.000 description 12
- 238000002474 experimental method Methods 0.000 description 12
- 239000003921 oil Substances 0.000 description 11
- 230000002269 spontaneous effect Effects 0.000 description 6
- 238000011161 development Methods 0.000 description 5
- 230000018109 developmental process Effects 0.000 description 5
- 239000012266 salt solution Substances 0.000 description 4
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 description 3
- 239000011780 sodium chloride Substances 0.000 description 3
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 2
- 238000004364 calculation method Methods 0.000 description 2
- 238000006073 displacement reaction Methods 0.000 description 2
- 239000011148 porous material Substances 0.000 description 2
- 238000011084 recovery Methods 0.000 description 2
- 238000007789 sealing Methods 0.000 description 2
- GYZGFUUDAQXRBT-UHFFFAOYSA-J calcium;disodium;disulfate Chemical compound [Na+].[Na+].[Ca+2].[O-]S([O-])(=O)=O.[O-]S([O-])(=O)=O GYZGFUUDAQXRBT-UHFFFAOYSA-J 0.000 description 1
- 239000010779 crude oil Substances 0.000 description 1
- 229920001971 elastomer Polymers 0.000 description 1
- 238000004836 empirical method Methods 0.000 description 1
- 239000012530 fluid Substances 0.000 description 1
- 239000007789 gas Substances 0.000 description 1
- 230000005484 gravity Effects 0.000 description 1
- 238000000703 high-speed centrifugation Methods 0.000 description 1
- 238000002347 injection Methods 0.000 description 1
- 239000007924 injection Substances 0.000 description 1
- 238000005065 mining Methods 0.000 description 1
- 229910052757 nitrogen Inorganic materials 0.000 description 1
- 238000005325 percolation Methods 0.000 description 1
- 239000003208 petroleum Substances 0.000 description 1
- 230000000704 physical effect Effects 0.000 description 1
- 239000004033 plastic Substances 0.000 description 1
- 239000003755 preservative agent Substances 0.000 description 1
- 230000002335 preservative effect Effects 0.000 description 1
- 238000005070 sampling Methods 0.000 description 1
- 229920006395 saturated elastomer Polymers 0.000 description 1
- 239000000243 solution Substances 0.000 description 1
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N15/00—Investigating characteristics of particles; Investigating permeability, pore-volume, or surface-area of porous materials
- G01N15/08—Investigating permeability, pore-volume, or surface area of porous materials
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N13/00—Investigating surface or boundary effects, e.g. wetting power; Investigating diffusion effects; Analysing materials by determining surface, boundary, or diffusion effects
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N15/00—Investigating characteristics of particles; Investigating permeability, pore-volume, or surface-area of porous materials
- G01N15/08—Investigating permeability, pore-volume, or surface area of porous materials
- G01N15/088—Investigating volume, surface area, size or distribution of pores; Porosimetry
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N24/00—Investigating or analyzing materials by the use of nuclear magnetic resonance, electron paramagnetic resonance or other spin effects
- G01N24/08—Investigating or analyzing materials by the use of nuclear magnetic resonance, electron paramagnetic resonance or other spin effects by using nuclear magnetic resonance
- G01N24/081—Making measurements of geologic samples, e.g. measurements of moisture, pH, porosity, permeability, tortuosity or viscosity
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N15/00—Investigating characteristics of particles; Investigating permeability, pore-volume, or surface-area of porous materials
- G01N15/08—Investigating permeability, pore-volume, or surface area of porous materials
- G01N2015/0813—Measuring intrusion, e.g. of mercury
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02A—TECHNOLOGIES FOR ADAPTATION TO CLIMATE CHANGE
- Y02A90/00—Technologies having an indirect contribution to adaptation to climate change
- Y02A90/30—Assessment of water resources
Abstract
The invention provides a quantitative research method for salt-containing shale oil reservoir imbibition. The method comprises the following steps: (1) acquiring the porosity and permeability of a core sample of a target shale oil reservoir; (2) obtaining T of core sample2A spectrum; (3) immersing the core sample in heavy water with the stratum mineralization degree being the same as that of the stratum water of the target shale reservoir, and recording time; (4) obtaining T of heavy water treated core sample at preset time point2A spectrum; (5) utilizing T obtained in step (2)2Spectrum and T obtained in step (4) at different time points2Respectively calculating spectrum to obtain the rock core extraction degree of the rock core sample at different time points, further calculating to obtain the total rock core extraction degree of the rock core sample, and utilizing T2Calculating the cut-off value and the salt dissolution rate to obtain T2Dividing the boundary value and recycling T2Value pair T2T of the spectrum2The relaxation times are divided to quantitatively characterize the imbibition strength and regularity.
Description
Technical Field
The invention belongs to the technical field of oil reservoir development, and particularly relates to a quantitative research method for salt-containing shale oil reservoir imbibition.
Background
Shale oil reservoir is widely distributed, and the strategic effect of effective development of the shale oil reservoir on the petroleum in China is more and more prominent. The shale oil reservoir has complex pore structure, poor physical property, small crude oil occurrence pore, large fluid seepage resistance and difficult establishment of an effective displacement system. At present, a certain research is provided aiming at the process research and the oil displacement theory of the shale oil reservoir imbibition between salts. The imbibition effect can improve the total production degree of the water drive. The research on the imbibition effect has important practical significance on the development potential of the saline shale oil reservoir, and the research on the reservoir imbibition effect by utilizing the saline shale oil core in a laboratory is not seen.
In a spontaneous imbibition experiment of a rock core of a shale oil reservoir between salts, the permeability of the rock core is low, and the interfacial tension is high, so that reverse imbibition mainly occurs under the control of capillary tubes, and salt dissolution is accompanied.
Disclosure of Invention
The invention aims to provide a quantitative research method for the imbibition effect of a salt-containing shale oil reservoir;
in order to achieve the purpose, the invention provides a quantitative research method for the imbibition of a salt-containing shale oil reservoir, wherein the method comprises the following steps:
(1) acquiring the porosity and permeability of a core sample of a target shale oil reservoir;
(2) obtaining T of core sample2A spectrum;
(3) immersing the core sample in heavy water with the stratum mineralization degree being the same as that of the stratum water of the target shale reservoir, and recording time;
(4) obtaining T of heavy water treated core sample at preset time point2A spectrum;
(5) utilizing T obtained in step (2)2Spectrum and T obtained in step (4) at different time points2Respectively calculating spectrum to obtain the rock core extraction degree of the rock core sample at different time points, further calculating to obtain the total rock core extraction degree of the rock core sample, and utilizing T2Calculating the cut-off value and the salt dissolution rate to obtain T2Dividing the boundary value and recycling T2Value pair T2T of the spectrum2The relaxation times are divided to quantitatively characterize the imbibition strength and regularity.
It should be understood that the numbers of the steps in the front of the steps of the present invention are only used for representing the numbers of the steps, and the sequence of the steps is not limited.
However, according to some embodiments of the present invention, the method of the present invention is performed in the order of step (1), step (2), step (3), step (4) and step (5) described above.
According to some embodiments of the invention, step (1) comprises drying the target shale oil reservoir core sample, and measuring the porosity and permeability of the shale oil reservoir core sample.
According to some specific embodiments of the present invention, the drying of step (1) comprises drying the core sample to be free of water.
It is to be understood that the term "water-free" as used herein means that the water content satisfies the requirements of the art, and is not absolutely free of water.
According to some embodiments of the present invention, the drying time in the step (1) is 24 to 48 hours.
According to some embodiments of the invention, step (1) comprises collecting a core sample of the target shale oil reservoir and obtaining gas porosity and permeability of the core sample.
According to some embodiments of the invention, step (2) comprises saturating the core sample with kerosene at a pressure of 12MPa to 16 MPa.
According to some embodiments of the invention, step (2) comprises pressurizing and saturating the core sample with kerosene, and then performing the nuclear magnetic resonance test and obtaining T2Spectra.
According to some embodiments of the invention, step (3) comprises immersing the core sample in heavy water having a formation salinity of 5 ppm.
According to some embodiments of the invention, step (3) comprises immersing the core sample in heavy water having the same formation mineralization as the formation water of the target shale reservoir under sealed conditions.
According to some embodiments of the invention, step (3) comprises suspending and immersing the core sample in heavy water having a bed mineralization equal to the formation mineralization of the formation water of the target shale reservoir.
According to some embodiments of the invention, step (3) comprises hanging the core sample into a heavy water beaker with 5 ppm of formation mineralization and sealing with a plastic wrap.
According to some embodiments of the invention, step (4) comprises performing the nmr test at predetermined time points, and plotting the different time points T2Spectra.
According to some embodiments of the present invention, the step (4) comprises performing the nmr test at predetermined time points of 0h, 0.5h, 1h, 2h, 4h, 7h, 10h, 23h, 31h, 52h, 3d, 8d, 18d and 50d, respectively, and plotting the different time points T2A spectrum; wherein the time point other than 0h has a fluctuation range of 15%.
According to some embodiments of the invention, there is a 10% fluctuation at the time point other than 0 h.
It is understood that the above-mentioned fluctuation range of 15% (10%) at the time point other than 0h means that the selected range of the predetermined time point may have a fluctuation of 15% (10%) on the basis of 0.5h, 1h, 2h, 4h, 7h, 10h, 23h, 31h, 52h, 3d, 8d, 18d and 50d, for example, 1h, the selected range of the predetermined time point is 1h + - (1h × 15%)) (or 1h + - ((1 h × 10%)).
According to some embodiments of the invention, wherein step (5) comprises using T obtained in step (2)2Spectrum and T obtained in step (4) at different time points2Respectively calculating spectrum to obtain the rock core extraction degree of the rock core sample at different time points, further calculating to obtain the total rock core extraction degree of the rock core sample, and utilizing T obtained from nuclear magnetic resonance test2Calculating the cut-off value and the salt dissolution rate to obtain T2Dividing the boundary value and recycling T2Value pair T2T of the spectrum2The relaxation times are divided to quantitatively characterize the imbibition strength and regularity.
According to some embodiments of the invention, wherein step (5) comprises using T2Calculating the cut-off value and the salt dissolution rate to obtain T2And (4) dividing the value.
According to some embodiments of the present invention, step (5) comprises calculating T using the following equation (1)2A boundary value:
wherein, T2 boundaryIs T2A boundary value; t is2 cutoffIs T2Cutoff value, in ms; s is the salt dissolution rate in%.
According to some embodiments of the invention, step (1) comprises collecting core samples of different lithologies representative of the target shale oil reservoir; and in step (5) using T obtained in step (2)2Spectrum and T obtained in step (4) at different time points2And respectively calculating the rock core extraction degrees of the rock core samples with different lithologies at different time points by the spectrum, and further calculating to obtain the total rock core extraction degree of the rock core samples.
According to the inventionSome embodiments, wherein step (5) comprises using T2A boundary value of T2T of the spectrum2The relaxation time is divided into two regions of imbibition oil production and salt dissolution oil release.
According to some embodiments of the invention, wherein step (5) is obtaining T by high speed centrifugation or empirical method2A cutoff value.
The above embodiments may be combined with each other arbitrarily without contradiction.
In conclusion, the invention provides a quantitative research method for the imbibition effect of the oil reservoir containing the salt shale. The method of the invention has the following advantages: the extraction degree of the imbibition effect in the water drive or huff and puff process of the salt-containing shale oil reservoir is quantitatively given, and a basis is provided for water injection development of the shale oil reservoir, particularly the salt-containing shale oil reservoir.
Drawings
FIG. 1 is the nuclear magnetic resonance T of core imbibition experiment No. 1 of example 12A spectrogram; legend represents the T at the start and end of the experiment respectively2Relaxation time spectrum, the peak value is reduced obviously after imbibition is finished.
FIG. 2 shows the NMR T of core 2 imbibition experiment in example 12A spectrogram; FIG. 2 shows the same meaning as FIG. 1;
FIG. 3 is nuclear magnetic resonance T of core imbibition experiment No. 3 of example 12A spectrogram; FIG. 3 shows the same meaning as FIG. 1;
FIG. 4 shows T in example 12A relation curve of a boundary value and a salt dissolution rate;
FIG. 5 shows T in example 12A relaxation time relationship curve;
FIG. 6 is a graph of spontaneous imbibition mining degrees of different lithologic cores of example 1 as a function of time.
Detailed Description
The following detailed description is provided for the purpose of illustrating the embodiments and the advantageous effects thereof, and is not intended to limit the scope of the present disclosure.
Example 1
The embodiment provides a quantitative research method for salt-containing shale oil reservoir imbibition, which comprises the following steps:
experimental methods and procedures: sampling, drying a rock core, and measuring porosity and permeability; second, the kerosene is used for pressurizing the saturated rock core and then the T is measured2A spectrum; thirdly, suspending the rock core into a heavy water big beaker with 5 ten thousand ppm stratum mineralization degree, sealing the big beaker with a preservative film by using a rubber band, and beginning to record time; fourthly, performing nuclear magnetic resonance test at preset time points, and drawing nuclear magnetic resonance T at different time nodes2A spectrum; use T2Calculating the total extraction degree of rock cores with different lithology and different time according to the spectrum2Algorithm of the boundary value (equation (1) below), and T is calculated2The relaxation time spectrum is divided to quantitatively represent the strength and rule of imbibition.
FIG. 1, FIG. 2 and FIG. 3 are T at the beginning and end of the 3-block core imbibition experiment, respectively2Relaxation time spectra. The T of salt solution imbibed by the oil reservoir containing salt shale is seen by combining figure 1, figure 2 and figure 32Boundary value will spontaneously imbibe T2The relaxation time spectrum is divided into two areas of the seepage oil recovery amount and the salt dissolution oil release amount, and the proportion of the seepage oil recovery amount and the salt dissolution oil release amount can respectively and quantitatively represent the relative strength of the seepage effect and the salt dissolution effect in the spontaneous seepage experiment of the rock core containing the salt shale oil.
T for imbibition salt solution of salt-containing shale oil reservoir2The boundary value can be calculated according to the following formula:
t calculated from the equation2Relationship curve of boundary value and salt dissolution rate (figure 4) and extraction degree and T2The relaxation time dependence curves (fig. 5) are very consistent.
Table 1 shows 3 cores with different T2Imbibition experimental result table of relaxation time range (total imbibition degree is measured by nuclear magnetic resonance T)2Spectral calculation). As can be seen from the data in Table 1: the maximum imbibition extraction degree of 3 rock cores is 6.09%, and the minimum imbibition extraction degree is 1.5%. The average imbibition extraction was 3.27%.
TABLE 13 percolation test results of different T2 relaxation time ranges of rock core
| Numbering | 1 | 2 | 3 |
| Lithology | Argillaceous dolomites | Argillaceous dolomites | Argillaceous glauberite rock |
| Nitrogen flooding T2Cutoff value/(ms) | 21.5 | 21.5 | 21.0 |
| Salt solubility S/(%) | 20.50 | 20.50 | 33.92 |
| Imbibition salt solution T2Boundary value/(ms) | 10.11 | 10.11 | 6.57 |
| Percentage of imbibition phiSuction device/(％) | 22.6 | 19.04 | 6.40 |
| Percentage of salt dissolution phiSolution/(％) | 77.40 | 80.96 | 93.60 |
| Imbibition degree/(%) | 6.09 | 2.23 | 1.50 |
The results of fig. 1-3 and table 1 show that: an experimental method for quantitative research on imbibition of the oil reservoir containing the salt shale is used for providing imbibition salt solution T2The calculation method of the boundary value quantitatively obtains the imbibition extraction degree and the salt dissolution extraction degree in the imbibition process, further quantitatively calculates the imbibition effect and the salt dissolution percentage, and can effectively research the relative strength of the imbibition effect in the saline shale oil reservoir development.
The data of the 5 rock cores gravity spontaneous imbibition experiment are shown in table 2 and fig. 6.
TABLE 2 spontaneous imbibition experimental data of different lithologic cores of typical shale oil reservoir
According to the table 2, the total extraction degree of the shale oil core in the spontaneous imbibition experiment is 11.71-49.43%, and the average extraction degree is 26.34%; before the extraction degree does not reach the relatively stable moment, the extraction degree and the time are approximately in a logarithmic relation, and the similarity of the fitting curve is high.
Claims (10)
1. A quantitative research method for salt-containing shale oil reservoir imbibition is disclosed, wherein the method comprises the following steps:
(1) acquiring the porosity and permeability of a core sample of a target shale oil reservoir;
(2) obtaining T of core sample2A spectrum;
(3) immersing the core sample in heavy water with the stratum mineralization degree being the same as that of the stratum water of the target shale reservoir, and recording time;
(4) obtaining T of heavy water treated core sample at preset time point2A spectrum;
(5) utilizing T obtained in step (2)2Spectrum and T obtained in step (4) at different time points2Respectively calculating spectrum to obtain the extraction degree of the rock core sample at different time points, further calculating to obtain the total extraction degree of the rock core sample, and utilizing T2Calculating the cut-off value and the salt dissolution rate to obtain T2Dividing the boundary value and recycling T2Value pair T2T of the spectrum2The relaxation times are divided to quantitatively characterize the imbibition strength and regularity.
2. The method according to claim 1, wherein step (1) comprises subjecting the target shale oil reservoir core sample to a drying process prior to measuring porosity and permeability thereof.
3. The method according to claim 1 or 2, wherein step (2) comprises saturating the core sample with kerosene at a pressure of 12MPa to 16 MPa.
4. The method according to any one of claims 1 to 3, wherein the step (2) comprises pressurizing and saturating the core sample with kerosene, and then performing the nuclear magnetic resonance test and obtaining T2Spectra.
5. The method as claimed in any one of claims 1 to 4, wherein the step (3) comprises immersing the core sample in heavy water having the same formation mineralization as that of formation water of the target shale reservoir under sealed conditions.
6. The method as claimed in any one of claims 1 to 5, wherein the step (3) comprises suspending and immersing the core sample in heavy water having a bed mineralization degree equal to a bed mineralization degree of the formation water of the target shale reservoir.
7. The method according to any one of claims 1 to 6, wherein the step (4) comprises performing the NMR test at predetermined time points of 0h, 0.5h, 1h, 2h, 4h, 7h, 10h, 23h, 31h, 52h, 3d, 8d, 18d and 50d, respectively, and plotting the different time points T2A spectrum; wherein the time point other than 0h has a fluctuation range of 15%.
8. The method of any one of claims 1 to 7, wherein step (5) comprises using T2Calculating the cut-off value and the salt dissolution rate to obtain T2And (4) dividing the value.
9. The method according to any one of claims 1 to 8, wherein the step (1) comprises collecting core samples with representative different lithologies in the target shale oil reservoir; and in step (5) using T obtained in step (2)2Spectrum and T obtained in step (4) at different time points2And respectively calculating the rock core extraction degrees of the rock core samples with different lithologies at different time points by the spectrum, and further calculating to obtain the total rock core extraction degree of the rock core samples.
10. The method of any one of claims 1 to 9, wherein step (5) comprises using T2A boundary value of T2T of the spectrum2The relaxation time is divided into two regions of imbibition oil production and salt dissolution oil release.
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Citations (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN103926186A (en) * | 2014-04-28 | 2014-07-16 | 西安石油大学 | Method for quantitatively evaluating influence of water injection on distribution of pore throats |
| US20170030819A1 (en) * | 2015-07-28 | 2017-02-02 | Chevron U.S.A. Inc. | Processes and Systems for Characterizing and Optimizing Fracturing Fluids |
| US20180003653A1 (en) * | 2016-06-24 | 2018-01-04 | The Board Of Regents Of The University Of Oklahoma | Methods of determining shale pore connectivity |
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|---|---|---|---|---|
| CN103926186A (en) * | 2014-04-28 | 2014-07-16 | 西安石油大学 | Method for quantitatively evaluating influence of water injection on distribution of pore throats |
| US20170030819A1 (en) * | 2015-07-28 | 2017-02-02 | Chevron U.S.A. Inc. | Processes and Systems for Characterizing and Optimizing Fracturing Fluids |
| US20180003653A1 (en) * | 2016-06-24 | 2018-01-04 | The Board Of Regents Of The University Of Oklahoma | Methods of determining shale pore connectivity |
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| 李兆敏 等: ""注入水矿化度对盐间页岩油储层物性影响研究"", 《特种油气藏》, vol. 27, no. 2, pages 131 - 137 * |
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