CN111425189B - Quality evaluation method and device for ultra-deep fracture-cavity carbonate reservoir and storage medium - Google Patents
Quality evaluation method and device for ultra-deep fracture-cavity carbonate reservoir and storage medium Download PDFInfo
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- 238000000034 method Methods 0.000 title claims abstract description 38
- BVKZGUZCCUSVTD-UHFFFAOYSA-L Carbonate Chemical compound [O-]C([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-L 0.000 title claims abstract description 36
- 238000013441 quality evaluation Methods 0.000 title claims abstract description 22
- 239000011435 rock Substances 0.000 claims abstract description 116
- 238000005259 measurement Methods 0.000 claims abstract description 59
- 239000012530 fluid Substances 0.000 claims description 137
- 238000012937 correction Methods 0.000 claims description 36
- 238000001228 spectrum Methods 0.000 claims description 36
- 238000011156 evaluation Methods 0.000 claims description 17
- 238000005481 NMR spectroscopy Methods 0.000 claims description 13
- 238000004088 simulation Methods 0.000 claims description 12
- 230000015572 biosynthetic process Effects 0.000 claims description 9
- 238000012360 testing method Methods 0.000 claims description 8
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- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 5
- 230000007797 corrosion Effects 0.000 description 3
- 238000005260 corrosion Methods 0.000 description 3
- 238000001303 quality assessment method Methods 0.000 description 3
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- 230000005540 biological transmission Effects 0.000 description 1
- 238000012512 characterization method Methods 0.000 description 1
- 238000005553 drilling Methods 0.000 description 1
- 238000001035 drying Methods 0.000 description 1
- 238000011010 flushing procedure Methods 0.000 description 1
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- E—FIXED CONSTRUCTIONS
- 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 application discloses an ultra-deep fracture-cavity carbonate reservoir quality evaluation method, device and storage medium, and belongs to the technical field of oil and gas engineering. The method comprises the following steps: acquiring measurement data of target layer rock and a T2 cut-off value; determining a reservoir quality factor for the target layer rock based on the measurement data and the T2 intercept value; and evaluating the reservoir quality of the target layer rock based on the reservoir quality factor of the target layer rock. According to the method and the device, the reservoir quality factor of the target layer rock can be determined through the measurement data and the T2 cut-off value of the target layer rock, and the reservoir quality is evaluated according to the reservoir quality factor of the target layer rock, and the accuracy of evaluating the reservoir quality of the target layer rock is improved due to the fact that the measurement data and the T2 cut-off value are determined.
Description
Technical Field
The application relates to the technical field of oil and gas engineering, in particular to a quality evaluation method and device for an ultra-deep fracture-cavity carbonate reservoir and a storage medium.
Background
The carbonate reservoir develops cracks and corrosion holes, has strong heterogeneity, and has more complex pore space structure and extremely strong anisotropy compared with the clastic rock reservoir, so that the carbonate reservoir quality evaluation technology becomes one of the problems of the carbonate logging evaluation technology.
Currently, the model for reservoir evaluation may include a porosity function model proposed for sandstone reservoirs, a Kozeny-Carman equation based on capillary theory proposed for homogeneous pore media, a Timur equation related to porosity, bound fluid saturation proposed for homogeneous sandstone, a dzuba equation proposed for homogeneous carbonate, etc. However, these models are not versatile and sometimes cannot be used to evaluate the reservoir quality of carbonate rock, resulting in failure to complete the evaluation of reservoir quality. Thus, there is a need for a method of reservoir quality assessment.
Disclosure of Invention
The embodiment of the application provides an ultra-deep fracture-cavity carbonate reservoir quality evaluation method, device and storage medium, which are used for solving the problems that reservoir quality evaluation cannot be performed and evaluation is inaccurate in the related technology. The technical scheme is as follows:
in one aspect, a method for evaluating quality of an ultra-deep fracture-cavity carbonate reservoir is provided, the method comprising:
acquiring measurement data of target layer rock and a T2 cut-off value;
determining a reservoir quality factor for the target layer rock based on the measurement data and the T2 intercept value;
and evaluating the reservoir quality of the target layer rock based on the reservoir quality factor of the target layer rock.
In some embodiments, the obtaining the T2 cut value of the target layer rock includes:
performing nuclear magnetic resonance test simulation on the target bedrock to obtain a plurality of porosity curves and a plurality of T2 distribution spectrums of the target bedrock under different function saturation;
the T2 cut-off value is determined from the plurality of porosity curves and the plurality of T2 distribution spectra.
In some embodiments, the measurement data includes a total porosity of the target layer rock;
the determining a reservoir quality factor of the target layer rock based on the measurement data and the T2 cut value comprises:
determining a bound fluid porosity of the target layer rock based on the T2 intercept value;
subtracting the bound fluid porosity from the total porosity to obtain a free fluid porosity;
a reservoir quality factor of the target layer rock is determined based on the total porosity, the bound fluid porosity, and the free fluid porosity.
In some embodiments, the determining the bound fluid porosity of the target layer rock based on the T2 cut value comprises:
determining a bound fluid porosity of the target formation based on the T2 cutoff value by a first formula;
Wherein said phi bvi For the bound fluid porosity, the T 2cutoff For the T2 cutoff value, the S (T 2 ) Is an expression of the T2 distribution spectrum.
In some embodiments, the determining the bound fluid porosity of the target layer rock based on the T2 cut value comprises:
determining a time range corresponding to the T2 truncated value from the T2 distribution spectrum;
based on the time range, the bound fluid porosity is determined.
In some embodiments, the determining the bound fluid porosity based on the time horizon comprises:
determining the bound fluid porosity based on the time range by a second formula;
wherein said phi bvi For the bound fluid porosity, the T 2cutoff For the T2 cutoff value, k is the third in the T2 distribution spectrumk times, C 1 Is constant.
In some embodiments, the determining a reservoir quality factor for the target layer rock based on the total porosity, the bound fluid porosity, and the free fluid porosity comprises:
determining a reservoir quality factor for the target layer rock based on the total porosity, the bound fluid porosity, and the free fluid porosity by a third formula;
Wherein K is the reservoir quality factor, delta is the correction amount, phi is the total porosity, phi bvi To bind the fluid porosity, the phi ffi For the free fluid porosity, the C 2 And p and q are constants.
In some embodiments, before the determining the reservoir quality factor for the target layer rock based on the measurement data and the T2 cut value, further comprises:
and acquiring a correction amount for the reservoir quality factor.
In some embodiments, the obtaining the correction to the reservoir quality factor comprises:
acquiring a correction amount for the reservoir quality factor by the following fourth formula based on the measurement data;
wherein, delta is the correction amount, alpha is the stoneley wave energy attenuation amount, beta is the face rate, phi fv For crack porosity, the phi ac Is the acoustic porosity, phi cnl For neutron porosity, the R t Is the resistivity of the undisturbed stratum, R is xo To flush the band resistivity, the w 1 The w is 2 And said w 3 Are all constant and the w 1 The w is 2 And said w 3 The sum of (2) is 1.
In another aspect, an ultra-deep fracture-cave carbonate reservoir quality evaluation apparatus is provided, the apparatus comprising:
The first acquisition module is used for acquiring measurement data of the target layer rock and a T2 cut-off value;
a determining module for determining a reservoir quality factor of the target layer rock based on the measurement data and the T2 cut-off value;
and the evaluation module is used for evaluating the reservoir quality of the target layer rock based on the reservoir quality factor of the target layer rock.
In some embodiments, the first acquisition module comprises:
the simulation sub-module is used for performing nuclear magnetic resonance test simulation on the target bedrock to obtain a plurality of porosity curves and a plurality of T2 distribution spectrums of the target bedrock under different function saturation;
a first determination submodule for determining the T2 cut-off value from the plurality of porosity curves and the plurality of T2 distribution spectrums.
In some embodiments, the measurement data includes a total porosity of the target layer rock;
the determining module includes:
a second determination submodule for determining a bound fluid porosity of the target layer rock based on the T2 intercept value;
a calculation sub-module for subtracting the bound fluid porosity from the total porosity to obtain a free fluid porosity;
a third determination submodule for determining a reservoir quality factor of the target layer rock based on the total porosity, the bound fluid porosity and the free fluid porosity.
In some embodiments, the second determination submodule is to:
determining a bound fluid porosity of the target formation based on the T2 cutoff value by a first formula;
wherein said phi bvi For the bound fluid porosity, the T 2cutoff For the T2 cutoff value, the S (T 2 ) Is an expression of the T2 distribution spectrum.
In some embodiments, the second determination submodule is to:
determining a time range corresponding to the T2 truncated value from the T2 distribution spectrum;
based on the time range, the bound fluid porosity is determined.
In some embodiments, the second determination submodule is further to:
determining the bound fluid porosity based on the time range by a second formula;
wherein said phi bvi For the bound fluid porosity, the T2 cu toff is the T2 cut-off value, k is the kth time, C in the T2 distribution spectrum 1 Is constant.
In some embodiments, the third determination submodule is to:
determining a reservoir quality factor for the target layer rock based on the total porosity, the bound fluid porosity, and the free fluid porosity by a third formula;
wherein K is the reservoir quality factor, delta is the correction amount, phi is the total porosity, phi bvi To bind the fluid porosity, the phi ffi For the free fluid porosity, the C 2 The place of saleBoth p and q are constants.
In some embodiments, the apparatus further comprises:
and the second acquisition module is used for acquiring the correction amount of the reservoir quality factor.
In some embodiments, the second acquisition module is configured to:
acquiring a correction amount for the reservoir quality factor by the following fourth formula based on the measurement data;
wherein, delta is the correction amount, alpha is the stoneley wave energy attenuation amount, beta is the face rate, phi fv For crack porosity, the phi ac Is the acoustic porosity, phi cnl For neutron porosity, the R t Is the resistivity of the undisturbed stratum, R is xo To flush the band resistivity, the w 1 The w is 2 And said w 3 Are all constant and the w 1 The w is 2 And said w 3 The sum of (2) is 1.
In another aspect, a computer readable storage medium is provided, in which a computer program is stored, which when executed by a processor, implements a reservoir quality evaluation method provided in the above aspect.
In another aspect, there is provided a terminal including:
a processor;
A memory for storing processor-executable instructions;
wherein the processor is configured to perform the steps of the reservoir quality assessment method provided in the above aspect.
In another aspect, there is provided a computer program product containing instructions which, when run on a computer, cause the computer to perform the steps of the reservoir quality assessment method provided in the above aspect.
The beneficial effects that technical scheme that this application embodiment provided include at least:
in the embodiment of the application, the measurement data and the T2 cut-off value of the target layer rock can be obtained, the reservoir quality factor of the target layer rock is determined according to the measurement data and the T2 cut-off value of the target layer rock, and then the reservoir quality is evaluated according to the reservoir quality factor of the target layer rock, and the accuracy of evaluating the reservoir quality of the target layer rock is improved due to the fact that the measurement data and the T2 cut-off value are determined.
Drawings
In order to more clearly illustrate the technical solutions of the embodiments of the present application, the drawings that are needed in the description of the embodiments will be briefly introduced below, and it is obvious that the drawings in the following description are only some embodiments of the present application, and that other drawings may be obtained according to these drawings without inventive effort for a person skilled in the art.
FIG. 1 is a flow chart of an ultra-deep fracture-cave carbonate reservoir quality evaluation method provided in an embodiment of the present application;
FIG. 2 is a flow chart of another method for evaluating quality of an ultra-deep fracture-cave carbonate reservoir according to an embodiment of the present application;
FIG. 3 is a schematic illustration of determining the porosity of a confining fluid by a T2 cut-off method provided in an embodiment of the present application;
FIG. 4 is a schematic diagram of T2 cut-off provided in an embodiment of the present application;
FIG. 5 is a chart of a nuclear magnetic resonance T2 spectrum provided in an embodiment of the present application;
fig. 6 is a schematic structural diagram of an ultra-deep fracture-cavity carbonate reservoir quality evaluation device according to an embodiment of the present application;
fig. 7 is a schematic structural diagram of a first obtaining module according to an embodiment of the present application;
fig. 8 is a schematic structural diagram of a determining module according to an embodiment of the present application;
FIG. 9 is a schematic structural view of another ultra-deep fracture-cave carbonate reservoir quality evaluation apparatus provided in an embodiment of the present application;
fig. 10 is a schematic structural diagram of a terminal according to an embodiment of the present application.
Detailed Description
For the purpose of making the objects, technical solutions and advantages of the present application more apparent, the embodiments of the present application will be described in further detail below with reference to the accompanying drawings.
Before explaining the embodiment of the present application in detail, an explanation is made on an application scenario related to the embodiment of the present application.
The carbonate reservoir develops cracks and corrosion holes, has strong heterogeneity, and has more complex pore space structure and extremely strong anisotropy compared with the clastic rock reservoir, so that the carbonate reservoir quality evaluation technology becomes one of the problems of the carbonate logging evaluation technology.
At present, since the oil field is exploited on a large scale, the quality evaluation of the reservoir is one of the directions of hot drilling and grinding of petroleum engineers, and the evolution process from rough to fine and from homogenization to heterogeneous theory is successively carried out. The model for reservoir evaluation may include a porosity function model proposed for sandstone reservoirs, a Kozeny-Carman equation based on capillary theory proposed for homogeneous pore media, a Timur equation related to porosity, bound fluid saturation proposed for homogeneous sandstone, a dzuba equation proposed for homogeneous carbonate, etc. However, these models are not versatile and sometimes cannot be used to evaluate the reservoir quality of carbonate rock, resulting in failure to complete the evaluation of reservoir quality.
Based on such a scenario, the embodiment of the application provides an ultra-deep fracture-cavity carbonate reservoir quality evaluation method capable of improving evaluation accuracy.
After the application scenario of the embodiment of the present application is described, a method for evaluating the quality of a reservoir provided by the embodiment of the present application will be described in detail below with reference to the accompanying drawings.
Fig. 1 is a flowchart of an ultra-deep fracture-cavity carbonate reservoir quality evaluation method provided in an embodiment of the present application, and referring to fig. 1, the method is applied to a terminal, and includes the following steps.
Step 101: and acquiring measurement data of the target layer rock and a T2 cut-off value.
Step 102: based on the measurement data and the T2 cutoff value, a reservoir quality factor of the target layer rock is determined.
Step 103: and evaluating the reservoir quality of the target layer rock based on the reservoir quality factor of the target layer rock.
In the embodiment of the application, the measurement data and the T2 cut-off value of the target layer rock can be obtained, the reservoir quality factor of the target layer rock is determined according to the measurement data and the T2 cut-off value of the target layer rock, and then the reservoir quality is evaluated according to the reservoir quality factor of the target layer rock, and the accuracy of evaluating the reservoir quality of the target layer rock is improved due to the fact that the measurement data and the T2 cut-off value are determined.
In some embodiments, obtaining the T2 cut value for the target layer rock includes:
performing nuclear magnetic resonance test simulation on the target bedrock to obtain a plurality of porosity curves and a plurality of T2 distribution spectrums of the target bedrock under different function saturation;
the T2 cut-off value is determined from the plurality of porosity curves and the plurality of T2 distribution spectra.
In some embodiments, the measurement data includes a total porosity of the target layer rock;
the determining a reservoir quality factor for the target layer rock based on the measurement data and the T2 cut-off value, comprising:
determining a bound fluid porosity of the target layer rock based on the T2 intercept value;
subtracting the bound fluid porosity from the total porosity to obtain a free fluid porosity;
a reservoir quality factor of the target layer rock is determined based on the total porosity, the bound fluid porosity, and the free fluid porosity.
In some embodiments, determining the bound fluid porosity of the target interval based on the T2 cut-off value comprises:
determining a bound fluid porosity of the target interval based on the T2 cutoff value by a first formula;
wherein phi is bvi To the bound fluid porosity, T 2cutoff For the T2 cut-off value, S (T 2 ) Is an expression of a T2 distribution spectrum.
In some embodiments, determining the bound fluid porosity of the target interval based on the T2 cut-off value comprises:
determining a time range corresponding to the T2 cut-off value from the T2 distribution spectrum;
based on the time frame, the bound fluid porosity is determined.
In some embodiments, determining the bound fluid porosity based on the time horizon comprises:
determining the bound fluid porosity based on the time frame by a second formula;
wherein phi is bvi To the bound fluid porosity, T 2cutoff For the T2 cutoff value, k is the kth time, C in the T2 distribution spectrum 1 Is constant.
In some embodiments, determining the reservoir quality factor for the target layer rock based on the total porosity, the bound fluid porosity, and the free fluid porosity comprises:
determining a reservoir quality factor for the target layer rock based on the total porosity, the bound fluid porosity, and the free fluid porosity by a third formula;
where K is the reservoir quality factor, delta is the correction, phi is the total porosity, phi bvi To bind the fluid porosity, phi ffi For the free fluid porosity, C 2 P and q are constants.
In some embodiments, prior to determining the reservoir quality factor for the target layer rock based on the measurement data and the T2 cut value, further comprising:
A correction amount for the reservoir quality factor is obtained.
In some embodiments, obtaining the correction to the reservoir quality factor includes:
acquiring a correction amount for the reservoir quality factor by the following fourth formula based on the measurement data;
wherein delta is the correction amount, alpha is the stoneley wave energy attenuation amount, beta is the face rate, phi fv Is the crack porosity phi ac Is the acoustic porosity, phi cnl For neutron porosity, R t Is the resistivity of the undisturbed stratum, R xo To flush the band resistivity, w 1 、w 2 And w 3 Are all constant and w 1 、w 2 And w 3 The sum of (2) is 1.
All the above optional technical solutions may be combined according to any choice to form an optional embodiment of the present application, which is not described in detail herein.
Fig. 2 is a flowchart of a method for evaluating quality of an ultra-deep fracture-cavity carbonate reservoir according to an embodiment of the present application, and referring to fig. 2, the method includes the following steps.
Step 201: and the terminal acquires the measurement data of the target layer rock and the T2 cut-off value.
As an example, the terminal may acquire measurement data of the target layer rock and the T2 cut value when receiving the evaluation instruction. The target layer rock may be a layer rock of ultra-deep layer fracture-cave carbonate rock.
Since the confining fluid resides in the small pores and the mobile fluid resides in the large pores, and the pore throat size is related to the pore size, the T2 cut-off value is related to the pore size. That is, fluids with a porosity less than the T2 cutoff value reside in the small pores and cannot be produced, and fluids with a porosity greater than the T2 cutoff value reside in the large pores and can flow freely. Thus, the bound fluid porosity can be determined by the T2 cut-off, the T2 cut-off dividing the effective porosity (MPHIT) into two parts, capillary bound water porosity (MBVITA) and free fluid porosity (MFFITA). Therefore, the terminal needs to acquire the T2 cut-off value. For ease of understanding, embodiments of the present application provide a schematic representation of T2 cut-off to determine the porosity of a bound fluid, see fig. 3.
As an example, the operation of the terminal to obtain the T2 cut value of the target layer rock may be: performing nuclear magnetic resonance test simulation on the target bed rock to obtain a plurality of porosity curves and a plurality of T2 distribution spectrums of the target bed rock under different function saturation; t2 cut-off values are determined from a plurality of porosity curves and a plurality of T2 distribution spectra. For ease of illustration, an embodiment of the present application provides a T2 cutoff schematic, see fig. 4.
As an example, the terminal may obtain the T2 cut-off value not only in the above manner, but also in other manners of ITon hometown. For example, the terminal may also receive a T2 cut-off value of the target bedrock entered by the worker through a specified operation. The designation operation may include a click operation, an input operation, a slide operation, a voice operation, and the like.
Since the T2 cut-off value needs to be determined by nuclear magnetic resonance measurements of the rock sample performed in the laboratory. Therefore, the terminal can perform nuclear magnetic resonance test simulation on the target bedrock. Alternatively, the staff member performs a nuclear magnetic resonance characterization of the target layer rock sample (after establishing the appropriate saturation value from the capillary pressure curve or directly drying the rock sample to the appropriate capillary pressure) under two saturation conditions where the target layer rock has water saturation sw=100% and Sw is equal to the irreducible water saturation. To achieve a bound water condition, the worker may employ a centrifuge technique or baffle technique (at a given capillary pressure) or a terminal simulated centrifuge technique or baffle technique. Then, a T2 distribution spectrum measured by 100% saturated water and a T2 distribution spectrum measured under a constraint state are measured.
For example, after the terminal performs nuclear magnetic resonance simulation on the target bedrock, a nuclear magnetic resonance T2 spectrum distribution diagram as shown in fig. 5 can be obtained.
It should be noted that the measurement data may include: stoneley wave energy attenuation alpha, face porosity beta, fracture porosity phi fv Porosity phi of sound wave ac Neutron porosity phi cnl Resistivity R of undisturbed stratum t Resistivity R of the flushing belt xo Total porosity of the fluid, layer depth, etc.
As an example, the terminal may store measurement data of the target layer rock in advance, or may be obtained from other devices, or may be input to the terminal by a specified operation by a worker when the quality of the reservoir of the target layer rock needs to be evaluated.
For example, the terminal may acquire measurement data as shown in table 1.
TABLE 1
In the examples of the present application, the data shown in table 1 are merely taken as examples, and the examples of the present application are not limited thereto.
Step 202: and the terminal determines the reservoir quality factor of the target layer rock based on the measurement data and the T2 cut-off value.
From the above, the measurement data may include a total porosity of the fluid of the target formation, so the terminal may determine a reservoir quality factor of the target formation based on the measurement data and the T2 intercept value by determining a bound fluid porosity of the target formation based on the T2 intercept value; subtracting the bound fluid porosity from the total porosity to obtain a free fluid porosity; a reservoir quality factor of the target layer rock is determined based on the total porosity, the bound fluid porosity, and the free fluid porosity.
It should be noted that, the operation of determining the bound fluid porosity of the target layer rock by the terminal based on the T2 cut-off value may at least include the following two modes.
In a first way, the terminal determines the bound fluid porosity of the target formation based on the T2 intercept value by a first formula described below.
In the first formula (1), φ is bvi To bind the fluid porosity, T 2cutoff Is a T2 cut-off value, S (T 2 ) Is an expression of a T2 distribution spectrum.
In the second mode, the terminal determines a time range corresponding to a T2 cut-off value from a T2 distribution spectrum; based on the time frame, the bound fluid porosity is determined.
It should be noted that, the time range corresponding to the T2 cut-off value may be 8-150ms (milliseconds).
As one example, the terminal may determine the bound fluid porosity based on a time horizon by the following second formula.
In the second formula (2), φ is bvi To bind the fluid porosity, T 2cutoff Is the T2 cut-off value, k is the kth time in the T2 distribution spectrum, C 1 Is constant.
For example, when T2 is 32ms, the porosity of the confining fluid can be determined to be 10.358% by the second equation (2). For example, when the total porosity is 29% and the bound fluid porosity is 10.358%, then a free fluid porosity of 19.293% can be obtained.
It should also be noted that, since the measurement data may include the total porosity of the fluid of the target layer rock, the total porosity of the fluid includes the bound fluid porosity and the free fluid porosity, the free fluid porosity may be obtained by subtracting the bound fluid porosity from the total porosity.
As one example, the terminal may determine the reservoir quality factor of the target layer rock based on the total porosity, the bound fluid porosity, and the free fluid porosity by the following third formula.
In the third formula (3), K is a reservoir quality factor, δ is a correction amount, and Φ is a total porosity, Φ bvi To bind the fluid porosity, phi ffi Is free fluid porosity, C 2 P and q are constants.
For example, when the correction amount is 0.06, and the constant C 2 P and q are 0.1, 2 and 2, respectively, the total porosity is 29%, the bound fluid porosity determined by the above second formula (2) at the end is 10.358%, and the free fluid porosity is 19.293%, the reservoir quality factor of the target bedrock is 2.6175mD (1 md= 0.9869233 ×10) obtained by the above third formula (3) -3 μm2)。
As an example, the operation of the terminal to determine the reservoir quality factor for the target layer rock based on the total porosity, the bound fluid porosity, and the free fluid porosity may include not only the above-described manner, but also other manners. For example, the terminal may also determine the reservoir quality factor of the target layer rock based on the total porosity, the bound fluid porosity, and the free fluid porosity by the fifth equation described below.
In the fifth formula (5), K is a reservoir quality factor, Φ is a total porosity, Φ bvi To bind the fluid porosity, phi ffi Is free fluid porosity, C 2 P and q are constants.
It is worth to say that, because when the reservoir quality factor of the target layer rock is determined by the third formula, correction can be performed through the correction amount, accuracy of determining the reservoir quality factor is improved, and further the subsequent evaluation result of the reservoir quality of the target layer rock is improved.
In the embodiment of the application, before determining the reservoir quality factor of the target layer rock based on the measurement data and the T2 cut-off value, the terminal may further obtain a correction amount for the reservoir quality factor.
As an example, the operation of the terminal to obtain the correction amount to the reservoir quality factor may be: based on the measurement data, a correction amount for the reservoir quality factor is obtained by the following fourth formula.
In the fourth formula (4), δ is a correction amount, α is a stoneley wave energy attenuation amount, β is a face rate, and Φ fv Is the crack porosity phi ac Is the acoustic porosity, phi cnl For neutron porosity, R t Is the resistivity of the undisturbed stratum, R xo To flush the band resistivity, w 1 、w 2 And w 3 Are all constant and w 1 、 w2 And w 3 The sum of (2) is 1.
It should be noted that, when the measurement data obtained by the terminal is the data shown in table 1, and the constant w 1 、w 2 And w 3 At 0.5, 0.2 and 0.3, respectively, the terminal can obtain the correction amount of 0.06 by the fourth formula (4) described above.
Step 203: and the terminal evaluates the reservoir quality of the target layer rock based on the reservoir quality factor of the target layer rock.
As an example, the terminal may compare the reservoir quality factor of the target bedrock with a preset quality threshold, determine that the reservoir quality of the target bedrock is acceptable when the reservoir quality factor of the target bedrock is greater than or equal to the preset quality threshold, and otherwise determine that the reservoir quality of the target bedrock is unacceptable.
It should be noted that the preset quality threshold is preset, and the preset quality threshold may be 1mD, 1.5m, or the like.
As an example, the terminal may further compare the reservoir quality factor of the target layer rock with a preset quality factor range, determine a quality factor range to which the reservoir quality factor of the target layer rock belongs, and determine the reservoir quality grade of the target layer rock from a correspondence between the quality factor range and the reservoir quality grade according to the quality factor range to which the reservoir quality factor of the target layer rock belongs.
Step 204: the terminal prompts the evaluation result through the prompt information.
As an example, the terminal may prompt the staff for the evaluation result of the target reservoir by playing the prompt message with voice and/or displaying the prompt message, where the prompt message may include the reservoir quality factor, the evaluation result, and the like of the target reservoir.
In the embodiment of the application, the terminal can acquire the measurement data and the T2 cut-off value of the target layer rock, determine the reservoir quality factor of the target layer rock according to the measurement data and the T2 cut-off value of the target layer rock, and then evaluate the reservoir quality according to the reservoir quality factor of the target layer rock.
After explaining the method for evaluating the quality of the ultra-deep fracture-cavity carbonate reservoir provided by the embodiment of the application, the device for evaluating the quality of the ultra-deep fracture-cavity carbonate reservoir provided by the embodiment of the application is described next.
Fig. 6 is a block diagram of an ultra-deep fracture and cave carbonate reservoir quality evaluation apparatus provided in an embodiment of the present disclosure, see fig. 6, which may be implemented in software, hardware, or a combination of both. The device comprises: a first acquisition module 601, a determination module 602, and an evaluation module 603.
A first obtaining module 601, configured to obtain measurement data of a target layer rock and a T2 cut-off value;
a determining module 602, configured to determine a reservoir quality factor of the target layer rock based on the measurement data and the T2 cut value;
and the evaluation module 603 is configured to evaluate the reservoir quality of the target bedrock based on the reservoir quality factor of the target bedrock.
In some embodiments, referring to fig. 7, the first obtaining module 601 includes:
the simulation submodule 6011 is used for performing nuclear magnetic resonance test simulation on the target bedrock to obtain a plurality of porosity curves and a plurality of T2 distribution spectrums of the target bedrock under different function saturation;
a first determination submodule 6012 for determining the T2 cut-off value from the plurality of porosity curves and the plurality of T2 distribution spectra.
In some embodiments, the measurement data includes a total porosity of the target layer rock;
Referring to fig. 8, the determining module 602 includes:
a second determination submodule 6021 for determining a bound fluid porosity of the target layer rock based on the T2 cut-off value;
a calculation submodule 6022 for subtracting the bound fluid porosity from the total porosity to obtain a free fluid porosity;
a third determination submodule 6023 for determining a reservoir quality factor of the target layer rock based on the total porosity, the bound fluid porosity and the free fluid porosity.
In some embodiments, the second determination submodule 6021 is configured to:
determining a bound fluid porosity of the target formation based on the T2 cutoff value by a first formula;
wherein said phi bvi For the bound fluid porosity, the T 2cutoff For the T2 cutoff value, the S (T 2 ) Is an expression of the T2 distribution spectrum.
In some embodiments, the second determination submodule 6021 is configured to:
determining a time range corresponding to the T2 truncated value from the T2 distribution spectrum;
based on the time range, the bound fluid porosity is determined.
In some embodiments, the second determination submodule 6021 is further configured to:
determining the bound fluid porosity based on the time range by a second formula;
Wherein said phi bvi For the bound fluid porosity, the T 2cutoff For the T2 cutoff value, k is the kth time, C in the T2 distribution spectrum 1 Is constant.
In some embodiments, the third determination submodule 6023 is configured to:
determining a reservoir quality factor for the target layer rock based on the total porosity, the bound fluid porosity, and the free fluid porosity by a third formula;
wherein K is the reservoir quality factor, delta is the correction amount, phi is the total porosity, phi bvi To bind the fluid porosity, the phi ffi For the free fluid porosity, the C 2 And p and q are constants.
In some embodiments, referring to fig. 9, the apparatus further comprises:
a second obtaining module 604 is configured to obtain a correction amount for the reservoir quality factor.
In some embodiments, the second obtaining module 604 is configured to:
acquiring a correction amount for the reservoir quality factor by the following fourth formula based on the measurement data;
wherein, delta is the correction amount, alpha is the stoneley wave energy attenuation amount, beta is the face rate, phi fv For crack porosity, the phi ac Is the acoustic porosity, phi cnl For neutron porosity, the R t Is the resistivity of the undisturbed stratum, R is xo To flush the band resistivity, the w 1 The w is 2 And said w 3 Are all constant and the w 1 The w is 2 And said w 3 The sum of (2) is 1.
In summary, in this embodiment of the present application, the terminal may obtain the measurement data and the T2 cut value of the target bedrock, determine the reservoir quality factor of the target bedrock according to the measurement data and the T2 cut value of the target bedrock, and then evaluate the reservoir quality according to the reservoir quality factor of the target bedrock, because the reservoir quality factor is determined by the measurement data and the T2 cut value, the porosity, the pore structure, the crack and the corrosion hole information of the target bedrock are combined, so that the permeability information of the target bedrock is mined to the greatest extent, thereby improving the accuracy of evaluating the reservoir quality of the target bedrock.
It should be noted that: the ultra-deep fracture-cavity carbonate reservoir quality evaluation device provided in the above embodiment is only exemplified by the above-mentioned division of each functional module when performing the reservoir quality evaluation of ultra-deep fracture-cavity carbonate, and in practical application, the above-mentioned functional allocation may be completed by different functional modules as required, i.e. the internal structure of the device is divided into different functional modules, so as to complete all or part of the above-mentioned functions. In addition, the device for evaluating quality of the ultra-deep fracture-cavity carbonate reservoir and the method for evaluating quality of the ultra-deep fracture-cavity carbonate reservoir provided in the above embodiments belong to the same concept, and detailed implementation processes of the device are shown in the method embodiments, which are not repeated here.
Fig. 10 shows a block diagram of a terminal 1000 according to an exemplary embodiment of the present application. The terminal 1000 may be: smart phones, tablet computers, notebook computers or desktop computers. Terminal 1000 can also be referred to by other names of user equipment, portable terminal, laptop terminal, desktop terminal, etc.
In general, terminal 1000 can include: a processor 1001 and a memory 1002.
The processor 1001 may include one or more processing cores, such as a 4-core processor, an 8-core processor, and so on. The processor 1001 may be implemented in at least one hardware form of DSP (Digital Signal Processing ), FPGA (Field-Programmable Gate Array, field programmable gate array), PLA (Programmable Logic Array ). The processor 1001 may also include a main processor, which is a processor for processing data in an awake state, also referred to as a CPU (Central Processing Unit ), and a coprocessor; a coprocessor is a low-power processor for processing data in a standby state. In some embodiments, the processor 1001 may integrate a GPU (Graphics Processing Unit, image processor) for rendering and drawing of content required to be displayed by the display screen. In some embodiments, the processor 1001 may also include an AI (Artificial Intelligence ) processor for processing computing operations related to machine learning.
Memory 1002 may include one or more computer-readable storage media, which may be non-transitory. Memory 1002 may also include high-speed random access memory, as well as non-volatile memory, such as one or more magnetic disk storage devices, flash memory storage devices. In some embodiments, a non-transitory computer readable storage medium in memory 1002 is used to store at least one instruction for execution by processor 1001 to implement the ultra-deep fracture-cave carbonate reservoir quality evaluation methods provided by the method embodiments herein.
In some embodiments, terminal 1000 can optionally further include: a peripheral interface 1003, and at least one peripheral. The processor 1001, the memory 1002, and the peripheral interface 1003 may be connected by a bus or signal line. The various peripheral devices may be connected to the peripheral device interface 1003 via a bus, signal wire, or circuit board. Specifically, the peripheral device includes: at least one of radio frequency circuitry 1004, touch display 1005, camera 1006, audio circuitry 1007, positioning component 1008, and power supply 1009.
Peripheral interface 1003 may be used to connect I/O (Input/Output) related at least one peripheral to processor 1001 and memory 1002. In some embodiments, processor 1001, memory 1002, and peripheral interface 1003 are integrated on the same chip or circuit board; in some other embodiments, either or both of the processor 1001, memory 1002, and peripheral interface 1003 may be implemented on a separate chip or circuit board, which is not limited in this embodiment.
Radio Frequency circuit 1004 is used to receive and transmit RF (Radio Frequency) signals, also known as electromagnetic signals. Radio frequency circuitry 1004 communicates with a communication network and other communication devices via electromagnetic signals. The radio frequency circuit 1004 converts an electrical signal into an electromagnetic signal for transmission, or converts a received electromagnetic signal into an electrical signal. Optionally, the radio frequency circuit 1004 includes: antenna systems, RF transceivers, one or more amplifiers, tuners, oscillators, digital signal processors, codec chipsets, subscriber identity module cards, and so forth. Radio frequency circuitry 1004 may communicate with other terminals via at least one wireless communication protocol. The wireless communication protocol includes, but is not limited to: metropolitan area networks, various generations of mobile communication networks (2G, 3G, 4G, and 5G), wireless local area networks, and/or WiFi (Wireless Fidelity ) networks. In some embodiments, the radio frequency circuitry 1004 may also include NFC (Near Field Communication ) related circuitry, which is not limited in this application.
The display screen 1005 is used to display a UI (User Interface). The UI may include graphics, text, icons, video, and any combination thereof. When the display 1005 is a touch screen, the display 1005 also has the ability to capture touch signals at or above the surface of the display 1005. The touch signal may be input to the processor 1001 as a control signal for processing. At this time, the display 1005 may also be used to provide virtual buttons and/or virtual keyboards, also referred to as soft buttons and/or soft keyboards. In some embodiments, display 1005 may be one, providing a front panel of terminal 1000; in other embodiments, display 1005 may be provided in at least two, separately provided on different surfaces of terminal 1000 or in a folded configuration; in still other embodiments, display 1005 may be a flexible display disposed on a curved surface or a folded surface of terminal 1000. Even more, the display 1005 may be arranged in a non-rectangular irregular pattern, i.e., a shaped screen. The display 1005 may be made of LCD (Liquid Crystal Display ), OLED (Organic Light-Emitting Diode) or other materials.
The camera assembly 1006 is used to capture images or video. Optionally, camera assembly 1006 includes a front camera and a rear camera. Typically, the front camera is disposed on the front panel of the terminal and the rear camera is disposed on the rear surface of the terminal. In some embodiments, the at least two rear cameras are any one of a main camera, a depth camera, a wide-angle camera and a tele camera, so as to realize that the main camera and the depth camera are fused to realize a background blurring function, and the main camera and the wide-angle camera are fused to realize a panoramic shooting and Virtual Reality (VR) shooting function or other fusion shooting functions. In some embodiments, camera assembly 1006 may also include a flash. The flash lamp can be a single-color temperature flash lamp or a double-color temperature flash lamp. The dual-color temperature flash lamp refers to a combination of a warm light flash lamp and a cold light flash lamp, and can be used for light compensation under different color temperatures.
The audio circuit 1007 may include a microphone and a speaker. The microphone is used for collecting sound waves of users and environments, converting the sound waves into electric signals, and inputting the electric signals to the processor 1001 for processing, or inputting the electric signals to the radio frequency circuit 1004 for voice communication. For purposes of stereo acquisition or noise reduction, the microphone may be multiple, each located at a different portion of terminal 1000. The microphone may also be an array microphone or an omni-directional pickup microphone. The speaker is used to convert electrical signals from the processor 1001 or the radio frequency circuit 1004 into sound waves. The speaker may be a conventional thin film speaker or a piezoelectric ceramic speaker. When the speaker is a piezoelectric ceramic speaker, not only the electric signal can be converted into a sound wave audible to humans, but also the electric signal can be converted into a sound wave inaudible to humans for ranging and other purposes. In some embodiments, audio circuit 1007 may also include a headphone jack.
The location component 1008 is used to locate the current geographic location of terminal 1000 to enable navigation or LBS (Location Based Service, location-based services). The positioning component 1008 may be a positioning component based on the united states GPS (Global Positioning System ), the beidou system of china, the grainer system of russia, or the galileo system of the european union.
Power supply 1009 is used to power the various components in terminal 1000. The power source 1009 may be alternating current, direct current, disposable battery or rechargeable battery. When the power source 1009 includes a rechargeable battery, the rechargeable battery may support wired or wireless charging. The rechargeable battery may also be used to support fast charge technology.
In some embodiments, terminal 1000 can further include one or more sensors 1010. The one or more sensors 1010 include, but are not limited to: acceleration sensor 1011, gyroscope sensor 1012, pressure sensor 1013, fingerprint sensor 1014, optical sensor 1015, and proximity sensor 1016.
The acceleration sensor 1011 can detect the magnitudes of accelerations on three coordinate axes of the coordinate system established with the terminal 1000. For example, the acceleration sensor 1011 may be used to detect components of gravitational acceleration in three coordinate axes. The processor 1001 may control the touch display 1005 to display a user interface in a landscape view or a portrait view according to the gravitational acceleration signal acquired by the acceleration sensor 1011. The acceleration sensor 1011 may also be used for the acquisition of motion data of a game or a user.
The gyro sensor 1012 may detect the body direction and the rotation angle of the terminal 1000, and the gyro sensor 1012 may collect the 3D motion of the user to the terminal 1000 in cooperation with the acceleration sensor 1011. The processor 1001 may implement the following functions according to the data collected by the gyro sensor 1012: motion sensing (e.g., changing UI according to a tilting operation by a user), image stabilization at shooting, game control, and inertial navigation.
Pressure sensor 1013 may be disposed on a side frame of terminal 1000 and/or on an underlying layer of touch display 1005. When the pressure sensor 1013 is provided at a side frame of the terminal 1000, a grip signal of the terminal 1000 by a user can be detected, and the processor 1001 performs right-and-left hand recognition or quick operation according to the grip signal collected by the pressure sensor 1013. When the pressure sensor 1013 is provided at the lower layer of the touch display 1005, the processor 1001 controls the operability control on the UI interface according to the pressure operation of the user on the touch display 1005. The operability controls include at least one of a button control, a scroll bar control, an icon control, and a menu control.
The fingerprint sensor 1014 is used to collect a fingerprint of the user, and the processor 1001 identifies the identity of the user based on the fingerprint collected by the fingerprint sensor 1014, or the fingerprint sensor 1014 identifies the identity of the user based on the collected fingerprint. Upon recognizing that the user's identity is a trusted identity, the processor 1001 authorizes the user to perform relevant sensitive operations including unlocking the screen, viewing encrypted information, downloading software, paying for and changing settings, etc. Fingerprint sensor 1014 may be provided on the front, back or side of terminal 1000. When a physical key or vendor Logo is provided on terminal 1000, fingerprint sensor 1014 may be integrated with the physical key or vendor Logo.
The optical sensor 1015 is used to collect ambient light intensity. In one embodiment, the processor 1001 may control the display brightness of the touch display 1005 based on the ambient light intensity collected by the optical sensor 1015. Specifically, when the intensity of the ambient light is high, the display brightness of the touch display screen 1005 is turned up; when the ambient light intensity is low, the display brightness of the touch display screen 1005 is turned down. In another embodiment, the processor 1001 may dynamically adjust the shooting parameters of the camera module 1006 according to the ambient light intensity collected by the optical sensor 1015.
Proximity sensor 1016, also referred to as a distance sensor, is typically located on the front panel of terminal 1000. Proximity sensor 1016 is used to collect the distance between the user and the front of terminal 1000. In one embodiment, when proximity sensor 1016 detects a gradual decrease in the distance between the user and the front face of terminal 1000, processor 1001 controls touch display 1005 to switch from the bright screen state to the off screen state; when proximity sensor 1016 detects a gradual increase in the distance between the user and the front face of terminal 1000, processor 1001 controls touch display 1005 to switch from the off-screen state to the on-screen state.
That is, the embodiments of the present application provide not only a terminal including a processor and a memory for storing instructions executable by the processor, where the processor is configured to perform the method in the embodiments shown in fig. 1 and 2, but also a computer readable storage medium having a computer program stored therein, where the computer program when executed by the processor may implement the method for evaluating quality of an ultra deep fracture-cave carbonate reservoir in the embodiments shown in fig. 1 and 2.
Those skilled in the art will appreciate that the structure shown in fig. 10 is not limiting and that terminal 1000 can include more or fewer components than shown, or certain components can be combined, or a different arrangement of components can be employed.
It will be understood by those skilled in the art that all or part of the steps for implementing the above embodiments may be implemented by hardware, or may be implemented by a program for instructing relevant hardware, where the program may be stored in a computer readable storage medium, and the storage medium may be a read-only memory, a magnetic disk or an optical disk, etc.
The foregoing description of the preferred embodiments of the present application is not intended to limit the invention to the particular embodiments of the present application, but to limit the scope of the invention to the particular embodiments of the present application.
Claims (7)
1. An ultra-deep fracture-cavity carbonate reservoir quality evaluation method, which is characterized by comprising the following steps:
acquiring measurement data of target layer rock and a T2 cut-off value;
determining a reservoir quality factor for the target layer rock based on the measurement data and the T2 intercept value;
evaluating the reservoir quality of the target layer rock based on the reservoir quality factor of the target layer rock;
the determining a reservoir quality factor of the target layer rock based on the measurement data and the T2 cut value comprises:
determining a bound fluid porosity of the target interval based on the T2 intercept value, comprising:
determining a time range corresponding to the T2 cut-off value from the T2 distribution spectrum, wherein the time range corresponding to the T2 cut-off value is 8-150ms;
determining the bound fluid porosity based on the time range;
before the reservoir quality factor of the target layer rock is determined based on the measurement data and the T2 cut value, the method further comprises:
acquiring a correction amount for the reservoir quality factor;
the obtaining a correction to the reservoir quality factor includes:
acquiring a correction amount for the reservoir quality factor by the following fourth formula based on the measurement data;
Wherein, delta is the correction amount, alpha is the stoneley wave energy attenuation amount, beta is the face rate, phi fv For crack porosity, the phi ac Is the acoustic porosity, phi cnl Is neutronPorosity of said R t Is the resistivity of the undisturbed stratum, R is xo To flush the band resistivity, the w 1 The w is 2 And said w 3 Are all constant and the w 1 The w is 2 And said w 3 The sum of (2) is 1;
the obtaining the T2 cut-off value of the target bedrock comprises the following steps:
performing nuclear magnetic resonance test simulation on the target bedrock to obtain a plurality of porosity curves and a plurality of T2 distribution spectrums of the target bedrock under different function saturation;
determining the T2 cut-off value from the plurality of porosity curves and the plurality of T2 distribution spectra;
the measurement data includes a total porosity of the target layer rock;
the determining the reservoir quality factor of the target layer rock based on the measurement data and the T2 cut value further comprises:
subtracting the bound fluid porosity from the total porosity to obtain a free fluid porosity;
a reservoir quality factor of the target layer rock is determined based on the total porosity, the bound fluid porosity, and the free fluid porosity.
2. The method of claim 1, wherein the determining the bound fluid porosity of the target layer rock based on the T2 intercept value comprises:
determining a bound fluid porosity of the target formation based on the T2 cutoff value by a first formula;
wherein said phi bvi For the bound fluid porosity, the T 2cutoff For the T2 cutoff value, the S (T 2 ) Is an expression of the T2 distribution spectrum.
3. The method of claim 1, wherein the determining the reservoir quality factor for the target layer rock based on the total porosity, the bound fluid porosity, and the free fluid porosity comprises:
determining a reservoir quality factor for the target layer rock based on the total porosity, the bound fluid porosity, and the free fluid porosity by a third formula;
wherein K is the reservoir quality factor, delta is the correction amount, phi is the total porosity, phi bvi To bind the fluid porosity, the phi ffi For the free fluid porosity, the C 2 And p and q are constants.
4. An ultra-deep fracture-cave carbonate reservoir quality evaluation device, the device comprising:
The first acquisition module is used for acquiring measurement data of the target layer rock and a T2 cut-off value;
a determining module for determining a reservoir quality factor of the target layer rock based on the measurement data and the T2 cut-off value;
the evaluation module is used for evaluating the reservoir quality of the target layer rock based on the reservoir quality factor of the target layer rock;
the determining module includes:
a second determination submodule for determining a bound fluid porosity of the target layer rock based on the T2 intercept value;
the second determination submodule is used for: determining a time range corresponding to the T2 cut-off value from the T2 distribution spectrum, wherein the time range corresponding to the T2 cut-off value is 8-150ms; determining the bound fluid porosity based on the time range;
the second acquisition module is used for acquiring a correction amount of the reservoir quality factor;
the second acquisition module is used for:
acquiring a correction amount for the reservoir quality factor by the following fourth formula based on the measurement data;
wherein, delta is the correction amount, alpha is the stoneley wave energy attenuation amount, beta is the face rate, phi fv For crack porosity, the phi ac Is the acoustic porosity, phi cnl For neutron porosity, the R t Is the resistivity of the undisturbed stratum, R is xo To flush the band resistivity, the w 1 The w is 2 And said w 3 Are all constant and the w 1 The w is 2 And said w 3 The sum of (2) is 1;
the first acquisition module includes:
the simulation sub-module is used for performing nuclear magnetic resonance test simulation on the target bedrock to obtain a plurality of porosity curves and a plurality of T2 distribution spectrums of the target bedrock under different function saturation;
a first determination submodule for determining the T2 cut-off value from the plurality of porosity curves and the plurality of T2 distribution spectrums;
the measurement data includes a total porosity of the target layer rock;
the determination module further includes:
a calculation sub-module for subtracting the bound fluid porosity from the total porosity to obtain a free fluid porosity;
a third determination submodule for determining a reservoir quality factor of the target layer rock based on the total porosity, the bound fluid porosity and the free fluid porosity.
5. The apparatus of claim 4, wherein the second determination submodule is to:
determining a bound fluid porosity of the target formation based on the T2 cutoff value by a first formula;
Wherein said phi bvi For the bound fluid porosity, the T 2cutoff For the T2 cutoff value, the S (T 2 ) Is an expression of the T2 distribution spectrum.
6. The apparatus of claim 4, wherein the third determination submodule is to:
determining a reservoir quality factor for the target layer rock based on the total porosity, the bound fluid porosity, and the free fluid porosity by a third formula;
wherein K is the reservoir quality factor, delta is the correction amount, phi is the total porosity, phi bvi To bind the fluid porosity, the phi ffi For the free fluid porosity, the C 2 And p and q are constants.
7. A computer readable storage medium, characterized in that the storage medium has stored therein a computer program which, when executed by a processor, implements the method of any of claims 1-3.
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