CN115163056A - Method and device for determining dynamic reserves, computer equipment and storage medium - Google Patents
Method and device for determining dynamic reserves, computer equipment and storage medium Download PDFInfo
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Abstract
The application provides a method and a device for determining dynamic reserves, computer equipment and a storage medium, and belongs to the technical field of oil and gas development. The method comprises the following steps: acquiring the pressure, the temperature and the yield of an oil well to be tested; determining the volume coefficient of crude oil in the oil well according to the temperature and the pressure, and determining the compression coefficient of the oil well; determining the flow characteristics of the oil well according to the yield, the volume coefficient and the compression coefficient, wherein the flow characteristics are used for indicating the flow stage of the oil well; when the flow characteristics are used for indicating that the flow phase of the oil well is a quasi-stable flow phase, determining the corresponding target yield of the oil well in the quasi-stable flow phase; and determining the dynamic reserves of the oil well according to the target yield, the volume coefficient and the compression coefficient. The method for determining the dynamic reserves can determine the dynamic reserves of the oil wells based on two dimensions of crude oil storage capacity and seepage capacity of the reservoir, so that the accuracy of the obtained dynamic reserves of the oil wells is improved.
Description
Technical Field
The application relates to the technical field of oil and gas development, in particular to a method and a device for determining dynamic reserves, computer equipment and a storage medium.
Background
Currently, fracture reformation technology is an important technology for increasing oil well production. Wherein the larger the dynamic reserve after the well modification, the larger the increased production of the well. Therefore, in order to determine the increased production of the well after fracture modification, it is necessary to determine the dynamic reserves of the well after fracture modification.
In the related art, the dynamic reserves of an oil well are determined by a ground micro-seismic method. The method comprises the following steps: acquiring seismic waves of a plurality of shot point seismic sources received by a detection point; determining the distribution condition of crude oil and rock in the reservoir according to the received seismic waves; and determining the dynamic reserve of the oil well after fracturing modification according to the distribution condition of crude oil and rock in the reservoir.
However, the dynamic reserve determined by the surface microseism method can only reflect the change of the crude oil storage amount in the oil well, the dynamic reserve of the oil well is related to both the crude oil storage amount and the seepage capacity of a reservoir, and when the reservoir seepage capacity of the oil well is low, the dynamic reserve of the oil well is low even if the crude oil storage amount in the oil well is large, so the accuracy of the dynamic reserve of the oil well obtained by the method is low.
Disclosure of Invention
The embodiment of the application provides a method and a device for determining dynamic reserves, computer equipment and a storage medium, which can improve the accuracy of drilling coincidence information of a exploration area. The technical scheme is as follows:
in one aspect, the present application provides a method for determining a dynamic reserve, where the method includes:
acquiring the pressure, temperature and yield of an oil well to be tested;
determining a volume factor of the crude oil in the well and determining a compressibility factor of the well based on the temperature and the pressure;
determining a flow characteristic of the well from the production, the volume factor and the compressibility factor, the flow characteristic being indicative of a flow phase in which the well is located;
when the flow characteristics are used for indicating that the flow phase of the oil well is a quasi-stable flow phase, determining a corresponding target yield of the oil well in the quasi-stable flow phase;
and determining the dynamic reserves of the oil well according to the target yield, the volume coefficient and the compression coefficient.
In one possible implementation, the determining a volume factor of the crude oil in the well based on the temperature and the pressure comprises:
according to the temperature, determining a temperature coefficient matched with the temperature;
determining the volume coefficient of crude oil in the oil well according to the temperature coefficient and the pressure by the following formula I;
the formula I is as follows: b =0.952-2.154 × 10 -4 P R +10 A
Wherein B represents the volume coefficient of the crude oil in the oil well, P R Represents the pressure and a represents the temperature coefficient.
In another possible implementation manner, the determining, according to the temperature, a temperature coefficient matching the temperature includes:
according to the temperature, determining a temperature coefficient matched with the temperature through the following formula five;
the formula five is as follows: a =0.1336 (2.647 × 10) -2 T-1)-1.2676
Wherein A represents the temperature coefficient and T represents the temperature.
In another possible implementation, the determining a compressibility of the oil well includes:
acquiring the compression coefficient of rock, the compression coefficient of crude oil and the compression coefficient of water in the oil well; and, determining the saturation of crude oil and the saturation of water in the well;
determining the compression coefficient of the oil well according to the compression coefficient of the rock, the compression coefficient of the crude oil, the compression coefficient of the water, the saturation of the crude oil and the saturation of the water by the following formula II;
the second formula is as follows: c t ＝C r +C o S o +C w S w
Wherein, C t Representing the compressibility of said well, C r Representing the compression coefficient, C, of said rock o Representing the compressibility of said crude oil, C w Represents the compressibility factor, S, of said water o Represents the saturation of the crude oil, S w Representing the degree of saturation of said water.
In another possible implementation, the determining the flow characteristic of the oil well from the production, the volume factor, and the compressibility factor includes:
determining a change in bottom hole pressure of the well based on the production, the volume factor, and the compressibility;
determining a first logarithm value corresponding to the bottom hole pressure and a second logarithm value corresponding to the bottom hole pressure according to the variation of the bottom hole pressure;
determining a flow characteristic of the well based on the first and second logarithm values.
In another possible implementation, the determining a change in bottom hole pressure of the well based on the production, the volume factor, and the compressibility factor includes:
obtaining the flowing time of crude oil in the oil well, the viscosity of the crude oil, the bottom hole depth of the oil well, the bottom hole permeability of the oil well, the area of a reservoir where the oil well is located, the pore volume of the reservoir where the oil well is located, the bottom hole resistance coefficient of the oil well, the shape factor of the oil well and the radius of the oil well;
determining the variation of the bottom hole pressure of the oil well according to the yield, the volume coefficient, the compression coefficient, the flow velocity and the time length of the crude oil in the oil well, the viscosity of the crude oil, the bottom hole depth of the oil well, the bottom hole permeability of the oil well, the area of a reservoir in which the oil well is positioned, the pore volume of the reservoir in which the oil well is positioned, the bottom hole resistance coefficient of the oil well, the shape factor of the oil well and the radius of the oil well by the following formula III;
the formula III is as follows:
wherein Δ p represents a change amount of a bottom hole pressure of the oil well, q represents the yield, μ represents a viscosity of the crude oil, B represents the volume coefficient, K represents a bottom hole permeability of the oil well, h represents a bottom hole depth of the oil well, a represents an area of a reservoir in which the oil well is located, S represents a bottom hole resistance coefficient of the oil well, r represents a radius of the oil well, C represents a bottom hole pressure of the oil well, and A representing the shape factor, V, of the well P Represents the pore volume, C, of the reservoir in which the well is located t Representing the compressibility of the well and t representing the length of time that the crude oil has flowed within the well.
In another possible implementation manner, the determining, according to the variation of the bottom hole pressure, a first logarithm value corresponding to the bottom hole pressure and a second logarithm value corresponding to the variation of the bottom hole pressure includes:
determining a first pair of values corresponding to the bottom hole pressure according to the variation of the bottom hole pressure and the flowing time of the crude oil in the oil well through the following formula six, and determining a second pair of values corresponding to the variation of the bottom hole pressure according to the yield, the volume coefficient, the pore volume of a reservoir in which the oil well is positioned, the compressibility of the oil well and the flowing time of the crude oil in the oil well through the following formula seven;
the formula six:
the formula seven:
wherein M represents the first logarithm, N represents the second logarithm, Δ p represents the change in the bottom hole pressure, q represents the production, B represents the volume factor, V represents the change in the bottom hole pressure, and P a pore volume, C, representing the reservoir in which the well is located t Representing the compressibility of the well and t representing the flow length of crude oil in the well.
In another possible implementation, the determining the flow characteristic of the oil well according to the first logarithm value and the second logarithm value includes:
when the first logarithmic value and the second logarithmic value are the same and both are the first logarithmic value, determining the flow characteristic of the oil well to indicate that the flow stage of the oil well is the quasi-stable flow stage.
In another possible implementation, the determining the dynamic reserve of the oil well according to the target production, the volume factor, and the compressibility factor includes:
determining a volume of fracturing fluid within the well;
determining the volume of crude oil in the pore space of the reservoir where the oil well is located according to the target yield, the volume coefficient and the compression coefficient;
and determining the difference between the volume of the crude oil in the pores of the reservoir where the oil well is located and the volume of the fracturing fluid as the dynamic reserve of the oil well.
In another possible implementation, the determining, based on the target production, the volume factor, and the compressibility, a volume of crude oil within pores of a reservoir in which the well is located includes:
acquiring the duration of the oil well in a quasi-stable flow stage and the target pressure corresponding to the oil well in the quasi-stable flow stage;
determining the volume of crude oil in the pores of the reservoir where the oil well is located according to the time length, the target pressure, the target yield, the volume coefficient and the compression coefficient through a fourth formula;
the formula four is as follows:
wherein, V s Representing the volume of crude oil in the pores of the reservoir in which the well is located, q representing the target production, B representing the volume factor of crude oil in the well, C t Representing the compressibility of the well, p representing the target pressure, and t representing the time period.
In another aspect, the present application provides a dynamic reserve determination apparatus, the apparatus comprising:
the acquisition module is used for acquiring the pressure, the temperature and the yield of an oil well to be tested;
a first determination module for determining a volume factor of the crude oil in the well and determining a compressibility factor of the well based on the temperature and the pressure;
a second determination module for determining a flow characteristic of the well based on the production, the volume factor and the compressibility factor, the flow characteristic being indicative of a flow phase in which the well is located;
a third determining module, configured to determine, when the flow characteristic is used to indicate that the flow phase in which the oil well is located is a quasi-steady flow phase, a corresponding target production rate when the oil well is in the quasi-steady flow phase;
and the fourth determination module is used for determining the dynamic reserves of the oil well according to the target yield, the volume coefficient and the compression coefficient.
In a possible implementation manner, the first determining module is configured to determine, according to the temperature, a temperature coefficient matched with the temperature; determining the volume coefficient of crude oil in the oil well according to the temperature coefficient and the pressure by the following formula I;
the formula I is as follows: b =0.952-2.154 × 10 -4 P R +10 A
Wherein B represents the volume coefficient of the crude oil in the oil well, P R Represents the pressure, and a represents the temperature coefficient.
In another possible implementation, the first determining module is configured to obtain a compressibility of rock, a compressibility of crude oil, and a compressibility of water in the well; and determining the saturation of crude oil and the saturation of water in the well;
determining the compression coefficient of the oil well according to the compression coefficient of the rock, the compression coefficient of the crude oil, the compression coefficient of the water, the saturation of the crude oil and the saturation of the water by the following formula II;
the formula II is as follows: c t ＝C r +C o S o +C w S w
Wherein, C t Representing the compressibility of said well, C r Representing the compression coefficient, C, of said rock o Representing the compressibility of said crude oil, C w Represents the compressibility factor, S, of said water o Represents the saturation of the crude oil, S w Representing the saturation of said water.
In another possible implementation manner, the second determining module is configured to determine a variation of the bottom hole pressure of the oil well according to the production, the volume coefficient, and the compressibility; determining a first logarithm value corresponding to the bottom hole pressure and a second logarithm value corresponding to the bottom hole pressure according to the variation of the bottom hole pressure; determining a flow characteristic of the well based on the first and second logarithm values.
In another possible implementation manner, the second determination module is configured to obtain a flowing time of the crude oil in the oil well, a viscosity of the crude oil, a bottom hole depth of the oil well, a bottom hole permeability of the oil well, an area of a reservoir where the oil well is located, a pore volume of the reservoir where the oil well is located, a bottom hole resistance coefficient of the oil well, a shape factor of the oil well, and a radius of the oil well; determining the variation of the bottom hole pressure of the oil well according to the yield, the volume coefficient, the compression coefficient, the flow speed duration of the crude oil in the oil well, the viscosity of the crude oil, the bottom hole depth of the oil well, the bottom hole permeability of the oil well, the area of a reservoir in which the oil well is positioned, the pore volume of the reservoir in which the oil well is positioned, the bottom hole resistance coefficient of the oil well, the shape factor of the oil well and the radius of the oil well by the following formula III;
the formula III is as follows:
wherein Δ p represents a change amount of a bottom hole pressure of the oil well, q represents the yield, μ represents a viscosity of the crude oil, B represents the volume coefficient, K represents a bottom hole permeability of the oil well, h represents a bottom hole depth of the oil well, a represents an area of a reservoir in which the oil well is located, S represents a bottom hole resistance coefficient of the oil well, r represents a radius of the oil well, C represents a bottom hole pressure of the oil well, and A representing the shape factor, V, of the well P Represents the pore volume, C, of the reservoir in which the well is located t Representing the compressibility of the well and t representing the length of time that the crude oil has flowed within the well.
In another possible implementation manner, the second determining module is configured to determine, according to the variation of the bottom-hole pressure and the flowing time length of the crude oil in the oil well, a first logarithm value corresponding to the bottom-hole pressure by using a sixth formula, and determine, according to the production, the volume coefficient, the pore volume of the reservoir where the oil well is located, the compressibility of the oil well, and the flowing time length of the crude oil in the oil well, a second logarithm value corresponding to the variation of the bottom-hole pressure by using a seventh formula;
the formula six:
the formula seven:
wherein M represents the first logarithm, N represents the second logarithm, Δ p represents the change in the bottom hole pressure, q represents the production, B represents the volume factor, V represents the change in the bottom hole pressure, and P represents the pore volume, C, of the reservoir in which the well is located t Representing the compressibility of the well and t representing the length of time that the crude oil within the well has flowed.
In another possible implementation manner, the second determining module is configured to determine, when the first logarithmic value and the second logarithmic value are the same and both are the first logarithmic value, the flow characteristic of the oil well to indicate that the flow phase of the oil well is a quasi-steady flow phase.
In another possible implementation, the fourth determining module is configured to determine a volume of fracturing fluid in the oil well; determining the volume of crude oil in pores of a reservoir where the oil well is located according to the target yield, the volume coefficient and the compression coefficient; and determining the difference between the volume of the crude oil in the pore space of the reservoir where the oil well is positioned and the volume of the fracturing fluid as the dynamic reserve of the oil well.
In another possible implementation manner, the fourth determining module is configured to obtain a duration that the oil well is in a pseudo-steady flow stage and a target pressure corresponding to that the oil well is in the pseudo-steady flow stage; determining the volume of crude oil in the pores of the reservoir where the oil well is located according to the time length, the target pressure, the target yield, the volume coefficient and the compression coefficient through a fourth formula;
the formula four is as follows:
wherein, V s Representing the volume of crude oil in the pores of the reservoir in which the well is located, q representing the target production, B representing the volume factor of crude oil in the well, C t Representing the compressibility of the well, p representing the meshThe target pressure, t, represents the time period.
In another aspect, an embodiment of the present application provides a computer device, where the computer device includes: a processor and a memory, the memory having stored therein at least one program code, the at least one program code being loaded by the processor and executed to implement the operations performed in the method for determining dynamic reserves of any of the possible implementations described above.
In another aspect, an embodiment of the present application provides a computer-readable storage medium, where at least one program code is stored in the computer-readable storage medium, and the at least one program code is loaded by a processor and executed to implement the operations performed in the method for determining dynamic reserves according to any of the foregoing possible implementations.
The technical scheme provided by the embodiment of the application has the beneficial effects that at least:
the embodiment of the application provides a method for determining dynamic reserves, which is characterized in that the flowing stage of an oil well is determined according to the pressure, the temperature and the yield of the oil well, and the pressure, the temperature and the yield of the oil well are all related to the seepage capability of a reservoir where the oil well is located, so that when the dynamic reserves of the oil well are determined according to the target yield corresponding to the oil well in the quasi-stable flowing stage, the factors of crude oil storage and the seepage capability of the reservoir are considered. Therefore, the method for determining the dynamic reserves provided by the embodiment of the application can determine the dynamic reserves of the oil well based on two dimensions of the crude oil storage capacity and the seepage capacity of the reservoir, so that the accuracy of the obtained dynamic reserves of the oil well is improved.
Drawings
In order to more clearly illustrate the technical solutions in the embodiments of the present application, the drawings required to be used in the description of the embodiments are briefly introduced below, and it is obvious that the drawings in the description below are only some embodiments of the present application, and it is obvious for those skilled in the art to obtain other drawings without creative efforts.
FIG. 1 is a flow chart illustrating a method for dynamic reserve determination in accordance with an exemplary embodiment;
FIG. 2 is a schematic illustration of a first logarithmic curve and a second logarithmic curve shown in accordance with an exemplary embodiment;
FIG. 3 is a block diagram illustrating a dynamic reserve determination apparatus in accordance with an exemplary embodiment;
FIG. 4 is a block diagram illustrating a configuration of a computer device according to an example embodiment.
Detailed Description
To make the objects, technical solutions and advantages of the present application more clear, embodiments of the present application will be described in further detail below with reference to the accompanying drawings.
FIG. 1 is a flow chart illustrating a method for dynamic reserve determination in accordance with an exemplary embodiment. Referring to fig. 1, the method includes:
101. the computer device obtains the pressure, temperature and production of the well to be tested.
In one possible implementation, a pressure sensor, a temperature sensor and a flow sensor are installed in the oil well to be tested. Correspondingly, the method comprises the following steps: the computer equipment sends a detection instruction to the pressure sensor, the pressure sensor detects the pressure of the oil well and returns the detected pressure to the computer equipment, and the computer equipment acquires the pressure of the oil well; the computer equipment sends a detection instruction to the temperature sensor, the temperature sensor detects the temperature of the oil well and returns the detected temperature to the computer equipment, and the computer equipment acquires the temperature of the oil well; and the computer equipment sends a detection instruction to the flow sensor, the flow sensor detects the flow of the crude oil produced by the oil well, the detected flow is returned to the computer equipment, and the computer equipment acquires the yield of the oil well.
Optionally, the pressure sensor is an electronic pressure gauge, for example, a storage pressure gauge. The temperature sensor is an electronic thermometer, for example an electronic infrared thermometer. The flow sensor is an ultrasonic flow meter.
The pressure of the oil well is the pressure of the oil well at the current time or the pressure of the oil well at a plurality of time points within a certain time period. For example, the pressure of a well is the pressure of the well at various points in time during the open-hole period. The temperature of the well is the temperature of the well at the current time or the temperature of the well at multiple time points within a certain time period. For example, the temperature of a well is the temperature of the well at various points in time during the open-hole period. The production of a well is the production of the well at the current time or the production of the well over a certain period of time. For example, the production of an oil well is the production of the oil well over a well-opening period.
It should be noted that the computer device needs to determine that the well to be tested satisfies the testing conditions before acquiring the pressure, temperature and production of the well to be tested.
In one possible implementation, the step of determining, by the computer device, that the oil well to be tested satisfies the test condition is: the computer equipment acquires the volume of the bridge plug in the oil well; and when the bridge plug in the oil well is fully dissolved until the volume of the bridge plug is zero, determining that the oil well to be tested meets the testing condition.
In another possible implementation, the computer device obtains the volume of the bridge plug in the oil well and the water-oil displacement rate of the oil well; and when the bridge plug in the oil well is fully dissolved until the volume of the bridge plug is zero and the water-oil displacement rate of the oil well is 100%, determining that the oil well to be tested meets the test conditions.
102. The computer device determines a volume factor of the crude oil in the well and a compressibility factor of the well based on the temperature and the pressure.
In one possible implementation, the volume factor of the crude oil in the well is related to the temperature of the well and the pressure of the well. Correspondingly, the step of determining the volume coefficient of the crude oil in the oil well by the computer device according to the temperature of the oil well and the pressure of the oil well is as follows: the computer equipment determines a temperature coefficient matched with the temperature according to the temperature of the oil well; determining the volume coefficient of crude oil in the oil well according to the temperature coefficient and the pressure of the oil well by the following formula I;
the formula I is as follows: b =0.952-2.154 × 10 -4 P R +10 A
Wherein B represents the volume coefficient of crude oil in the oil well, P R Indicating pressureForce, a, represents the temperature coefficient.
In one possible implementation manner, the step of determining, by the computer device, a temperature coefficient matching the temperature according to the temperature of the oil well is as follows: the computer equipment determines a temperature coefficient matched with the temperature according to the temperature of the oil well by the following formula V;
the formula five is as follows: a =0.1336 (2.647 × 10) -2 T-1) -1.2676; wherein A represents the temperature coefficient and T represents the temperature of the oil well.
In one possible implementation, the compressibility of the well is related to the compressibility of rock, the compressibility of crude oil, and the compressibility of water within the well. Correspondingly, the computer device determines the compressibility of the oil well by: the computer equipment acquires the compression coefficient of rock, the compression coefficient of crude oil and the compression coefficient of water in the oil well; and determining the saturation of crude oil and the saturation of water in the oil well; determining the compression coefficient of the oil well according to the compression coefficient of the rock, the compression coefficient of the crude oil, the compression coefficient of the water, the saturation of the crude oil and the saturation of the water by the following formula II;
the formula II is as follows: c t ＝C r +C o S o +C w S w
Wherein, C t Representing the compressibility of the well, C r Representing the compressibility of the rock, C o Representing the compressibility of the crude oil, C w Denotes the compressibility factor, S, of water o Denotes the saturation of the crude oil, S w Indicating the degree of saturation of the water.
103. The computer device determines the flow characteristics of the well based on the production, volume factor and compressibility factor.
The flow characteristic is used to indicate the flow phase in which the well is located.
In one possible implementation, the step of the computer device determining the flow characteristics of the well based on the production, the volume factor and the compressibility is: the computer equipment determines the variation of the bottom hole pressure of the oil well according to the yield, the volume coefficient and the compression coefficient; determining a first logarithm value corresponding to the bottom hole pressure and a second logarithm value corresponding to the bottom hole pressure according to the variation of the bottom hole pressure; based on the first and second logarithm values, a flow characteristic of the well is determined.
In one possible implementation, the step of determining, by the computer device, the variation in the bottom hole pressure of the well based on the production, the volume factor, and the compressibility is: the computer equipment acquires the flowing time of crude oil in the oil well, the viscosity of the crude oil, the bottom hole depth of the oil well, the bottom hole permeability of the oil well, the area of a reservoir where the oil well is positioned, the pore volume of the reservoir where the oil well is positioned, the bottom hole resistance coefficient of the oil well, the shape factor of the oil well and the radius of the oil well;
determining the variation of the bottom hole pressure of the oil well according to the yield, the volume coefficient, the compression coefficient, the flow speed duration of the crude oil in the oil well, the viscosity of the crude oil, the bottom hole depth of the oil well, the bottom hole permeability of the oil well, the area of a reservoir where the oil well is located, the pore volume of the reservoir where the oil well is located, the bottom hole resistance coefficient of the oil well, the shape factor of the oil well and the radius of the oil well by the following formula III;
the formula III is as follows:
where Δ p represents a change in bottom hole pressure of the well, q represents a yield, μ represents a viscosity of the crude oil, B represents a volume coefficient of the crude oil in the well, K represents a bottom hole permeability of the well, h represents a bottom hole depth of the well, a represents an area of a reservoir in which the well is located, S represents a bottom hole resistance coefficient of the well, r represents a radius of the well, C A Representing the shape factor, V, of the well P Represents the pore volume, C, of the reservoir in which the well is located t Representing the compressibility of the well and t representing the length of time the crude oil flows in the well.
In one possible implementation manner, the step of determining, by the computer device, a first logarithm corresponding to the bottom hole pressure and a second logarithm corresponding to the bottom hole pressure according to the variation of the bottom hole pressure includes: the computer equipment determines a first logarithm value corresponding to the bottom hole pressure according to the variation of the bottom hole pressure and the flowing time length of crude oil in the oil well through the following formula six, and determines a second logarithm value corresponding to the variation of the bottom hole pressure through the following formula seven according to the yield, the volume coefficient, the pore volume of a reservoir where the oil well is located, the compression coefficient of the oil well and the flowing time length of the crude oil in the oil well;
formula six:
the formula seven:
wherein M represents a first logarithm, N represents a second logarithm, Δ p represents the change in bottom hole pressure, q represents production, B represents the volume factor of the crude oil in the well, V P Represents the pore volume, C, of the reservoir in which the well is located t Representing the compressibility of the well and t representing the length of time that the crude oil is flowing in the well.
It should be noted that the first pair of values and the second pair of values are obtained by left-side and right-side transformation of formula three; firstly, the three sides of the formula are respectively derived from t:
then, the left side of the formula is multiplied by t to obtain a logarithm value M, and the right side of the formula is multiplied by t to obtain a logarithm value N.
In one possible implementation, referring to fig. 2, a first logarithmic curve is used to represent a first logarithmic curve over time, and a second logarithmic curve is used to represent a second logarithmic curve over time. The flow phase in which the well is located comprises a first phase: wellbore reservoir flow phase, second phase: skin effect transition phase, third phase: fracture formation bilinear flow phase, fourth phase: a formation seam reconstruction zone linear flow stage, a fifth stage: inter-fracture disturbed flow phase, sixth phase: pseudo-stationary flow phase.
In one possible implementation, the step of determining, by the computer device, the flow characteristic of the well based on the first and second logarithm values is: when the first and second logarithmic values are the same and both first logarithmic values, the computer means determines the flow characteristic of the well for indicating that the flow phase in which the well is located is a pseudo-steady flow phase.
The first value can range from any value between 0.95 and 1.05, e.g., 0.99, 1.00, 10.1, etc.; in the embodiment of the present application, the magnitude of the first numerical value is not particularly limited, and may be modified and set as needed. Optionally, the first value is 1.
104. When the flow characteristic is used to indicate that the flow phase in which the well is located is a pseudo-steady flow phase, the computer determines a corresponding target production rate for the well when in the pseudo-steady flow phase.
In one possible implementation, the computer device determines a target production rate corresponding to the oil well in the pseudo-steady flow phase according to a time period corresponding to the pseudo-steady flow phase. Correspondingly, the method comprises the following steps: the computer equipment determines a corresponding target time period when the oil well is in a quasi-stable flow stage; selecting the yield corresponding to the target time period from the yields of the oil wells; and taking the yield corresponding to the target time period as the target yield corresponding to the oil well in the quasi-stable flowing stage.
105. And the computer equipment determines the dynamic reserves of the oil well according to the target yield, the volume coefficient and the compression coefficient.
In one possible implementation, the dynamic reserves of the well are related to the corresponding target production when the well is in a pseudo-steady flow phase, the volume factor of the crude oil in the well, and the compressibility factor of the well. Correspondingly, the step of determining the dynamic reserves of the oil well by the computer equipment according to the target yield, the volume coefficient and the compression coefficient comprises the following steps: determining, by a computer device, a volume of fracturing fluid in an oil well; determining the volume of crude oil in the pores of the reservoir where the oil well is located according to the target yield, the volume coefficient and the compression coefficient; and determining the difference between the volume of the crude oil in the pores of the reservoir where the oil well is located and the volume of the fracturing fluid as the dynamic reserve of the oil well.
In one possible implementation, the computer device obtains the volume of fracturing fluid injected into the well and the volume of fluid removed from the wellAnd determining the difference between the volume of the fracturing fluid injected into the oil well and the volume of the fracturing fluid discharged from the oil well as the volume of the fracturing fluid in the oil well. Optionally, volume of fracturing fluid in well is V F And (4) showing.
In one possible implementation, the step of determining, by the computer device, the volume of crude oil in the pores of the reservoir in which the well is located, based on the target production, the volume factor and the compressibility, is: the computer equipment acquires the duration of a quasi-stable flow stage of an oil well and the target pressure of the quasi-stable flow stage; determining the volume of crude oil in the pores of the reservoir where the oil well is located according to the time length, the target pressure, the target yield, the volume coefficient and the compression coefficient through the following formula IV;
the formula four is as follows:
wherein, V s Representing the volume of crude oil in the pores of the reservoir in which the well is located, q representing the target production, B representing the volume factor of the crude oil in the well, C t Representing the compressibility of the well, p representing the target pressure, and t representing the duration.
The point to be noted is that the formula four is obtained by conversion after derivation of the formula three on time; firstly, the three sides of the formula are respectively derived from t:
then, multiplying the formula by t to obtain
After the change, we obtained:
wherein the volume V of crude oil in the pores of the reservoir in which the well is located s Pore volume V of reservoir in which oil well is located P The same is true.
In one possible implementation, the computer device determines a difference between a volume of crude oil and a volume of fracturing fluid in pores of a reservoir in which the well is located as a dynamic reserve of the well. Optionally, V for dynamic reserves of the well 0 Is shown as V 0 ＝Vs-V F (ii) a Wherein Vs represents the volume of crude oil in the pores of the reservoir in which the well is located, V F Representing the volume of fracturing fluid in the well.
It should be noted that the larger the dynamic reserve of the well, the greater the porosity of the well after the formation has been modified. Correspondingly, the computer equipment can also determine the porosity of the oil well after the reservoir is modified according to the dynamic reserve of the oil well. Wherein the step of the computer device determining the porosity of the reservoir is: the computer equipment acquires the volume of a reservoir where an oil well is located; determining the porosity of the reservoir where the oil well is located after modification according to the dynamic reserve of the oil well and the volume of the reservoir where the oil well is located by the following formula eight;
the formula eight:
wherein phi is L Porosity, V, after reformation of the reservoir in which the well is located R Representing the volume of the reservoir in which the well is located, V 0 Representing the dynamic reserves of the well.
The embodiment of the application provides a method for determining dynamic reserves, which is characterized in that the flowing stage of an oil well is determined according to the pressure, the temperature and the yield of the oil well, and the pressure, the temperature and the yield of the oil well are all related to the seepage capability of a reservoir where the oil well is located, so that when the dynamic reserves of the oil well are determined according to the target yield corresponding to the oil well in the quasi-stable flowing stage, the factors of crude oil storage and the seepage capability of the reservoir are considered. Therefore, the method for determining the dynamic reserves provided by the embodiment of the application can determine the dynamic reserves of the oil well based on two dimensions of the crude oil storage capacity and the seepage capacity of the reservoir, so that the accuracy of the obtained dynamic reserves of the oil well is improved.
FIG. 3 is a block diagram illustrating a dynamic reserve determination apparatus in accordance with an exemplary embodiment. Referring to fig. 3, the apparatus includes:
an obtaining module 301, configured to obtain pressure, temperature, and yield of an oil well to be tested;
a first determination module 302 for determining a volume factor of the crude oil in the oil well and determining a compressibility factor of the oil well based on the temperature and the pressure;
a second determining module 303, configured to determine a flow characteristic of the oil well according to the production, the volume factor and the compressibility, where the flow characteristic is used to indicate a flow phase of the oil well;
a third determining module 304, configured to determine a corresponding target production rate when the oil well is in the quasi-stable flow phase when the flow characteristic is used to indicate that the flow phase in which the oil well is in is the quasi-stable flow phase;
a fourth determination module 305 for determining the dynamic reserves of the well based on the target production, the volume factor, and the compressibility.
In a possible implementation manner, the first determining module 302 is configured to determine, according to a temperature, a temperature coefficient matching the temperature; determining the volume coefficient of crude oil in the oil well according to the temperature coefficient and the pressure by the following formula I;
the formula I is as follows: b =0.952-2.154 × 10 -4 P R +10 A
Wherein B represents the volume coefficient of crude oil in the oil well, P R Denotes pressure, and a denotes temperature coefficient.
In another possible implementation, the method includes a first determination module for obtaining a compressibility of rock, a compressibility of crude oil, and a compressibility of water in the well; and determining the saturation of crude oil and the saturation of water in the oil well;
determining the compression coefficient of the oil well according to the compression coefficient of the rock, the compression coefficient of the crude oil, the compression coefficient of the water, the saturation of the crude oil and the saturation of the water by the following formula II;
the second formula is as follows: c t ＝C r +C o S o +C w S w
Wherein, C t Representing the compressibility of the well, C r Representing the compressibility of the rock, C o Representing the compressibility of the crude oil, C w Denotes the compressibility factor, S, of water o Representing crude oilDegree of saturation, S w Indicating the degree of saturation of the water.
In another possible implementation manner, the second determining module 303 is configured to determine a variation of the bottom hole pressure of the oil well according to the production, the volume coefficient, and the compressibility; determining a first logarithm value corresponding to the bottom hole pressure and a second logarithm value corresponding to the bottom hole pressure according to the variation of the bottom hole pressure; based on the first and second pair of values, a flow characteristic of the well is determined.
In another possible implementation manner, the second determining module 303 is configured to obtain a flowing time of the crude oil in the oil well, a viscosity of the crude oil, a bottom hole depth of the oil well, a bottom hole permeability of the oil well, an area of a reservoir where the oil well is located, a pore volume of the reservoir where the oil well is located, a bottom hole resistance coefficient of the oil well, a shape factor of the oil well, and a radius of the oil well; determining the variation of the bottom hole pressure of the oil well according to the yield, the volume coefficient, the compression coefficient, the flow speed duration of the crude oil in the oil well, the viscosity of the crude oil, the bottom hole depth of the oil well, the bottom hole permeability of the oil well, the area of a reservoir where the oil well is located, the pore volume of the reservoir where the oil well is located, the bottom hole resistance coefficient of the oil well, the shape factor of the oil well and the radius of the oil well by the following formula III;
the formula III is as follows:
wherein Δ p represents a change in bottom hole pressure of the well, q represents a yield, μ represents a viscosity of the crude oil, B represents a volume coefficient, K represents a bottom hole permeability of the well, h represents a bottom hole depth of the well, a represents an area of a reservoir in which the well is present, S represents a bottom hole resistance coefficient of the well, r represents a radius of the well, C A Representing the form factor, V, of the well P Represents the pore volume, C, of the reservoir in which the well is located t Representing the compressibility of the well and t representing the length of time the crude oil flows in the well.
In another possible implementation manner, the second determining module 303 is configured to determine, according to the variation of the bottom-hole pressure and the flowing time of the crude oil in the oil well, a first logarithm value corresponding to the bottom-hole pressure by using a sixth formula, and determine, according to the yield, the volume coefficient, the pore volume of the reservoir where the oil well is located, the compressibility of the oil well, and the flowing time of the crude oil in the oil well, a second logarithm value corresponding to the variation of the bottom-hole pressure by using a seventh formula;
formula six:
the formula seven:
wherein M represents a first logarithm, N represents a second logarithm, Δ p represents a change in bottom hole pressure, q represents production, B represents a volume factor, and V represents P Represents the pore volume, C, of the reservoir in which the well is located t Representing the compressibility of the well and t representing the length of time the crude oil flows in the well.
In another possible implementation manner, the second determining module 303 is configured to determine the flow characteristic of the oil well to indicate that the flow phase of the oil well is a quasi-steady flow phase when the first logarithm value and the second logarithm value are the same and are both the first logarithm values.
In another possible implementation, a fourth determination module 305 is used to determine a volume of fracturing fluid in the well; determining the volume of crude oil in the pores of the reservoir where the oil well is located according to the target yield, the volume coefficient and the compression coefficient; and determining the difference between the volume of the crude oil in the pore space of the reservoir where the oil well is located and the volume of the fracturing fluid as the dynamic reserve of the oil well.
In another possible implementation manner, the fourth determining module 305 is configured to obtain a duration of the oil well in the quasi-steady flow stage and a target pressure corresponding to the oil well in the quasi-steady flow stage; determining the volume of crude oil in the pores of the reservoir where the oil well is located according to the time length, the target pressure, the target yield, the volume coefficient and the compression coefficient through the following formula IV;
the formula four is as follows:
wherein, V s Representing the volume of crude oil in the pores of the reservoir in which the well is located, q representing the target production, B representing the volume factor of the crude oil in the well, C t Representing the compressibility of the well, p representing the target pressure, and t representing the duration.
The embodiment of the application provides a device for determining dynamic reserves, wherein the flowing stage of an oil well is determined according to the pressure, the temperature and the yield of the oil well, and the pressure, the temperature and the yield of the oil well are all related to the seepage capability of a reservoir where the oil well is located, so that when the dynamic reserves of the oil well are determined according to the target yield corresponding to the oil well in the quasi-stable flowing stage, the factors of crude oil storage and the seepage capability of the reservoir are considered. Therefore, the device for determining the dynamic reserves provided by the embodiment of the application can determine the dynamic reserves of the oil wells based on two dimensions of the crude oil storage capacity and the seepage capacity of the reservoir, so that the accuracy of the obtained dynamic reserves of the oil wells is improved.
Fig. 4 shows a block diagram of a terminal 400 according to an exemplary embodiment of the present invention. The terminal 400 may be: a smart phone, a tablet computer, an MP3 player (Moving Picture Experts Group Audio Layer III, motion video Experts compression standard Audio Layer 3), an MP4 player (Moving Picture Experts Group Audio Layer IV, motion video Experts compression standard Audio Layer 4), a notebook computer, or a desktop computer. The terminal 400 may also be referred to by other names such as user equipment, portable terminal, laptop terminal, desktop terminal, etc.
In general, the terminal 400 includes: a processor 401 and a memory 402.
In some embodiments, the terminal 400 may further optionally include: a peripheral interface 403 and at least one peripheral. The processor 401, memory 402 and peripheral interface 403 may be connected by buses or signal lines. Each peripheral may be connected to the peripheral interface 403 via a bus, signal line, or circuit board. Specifically, the peripheral device includes: at least one of a radio frequency circuit 404, a display screen 405, a camera 406, an audio circuit 407, a positioning component 408, and a power supply 409.
The peripheral interface 403 may be used to connect at least one peripheral related to I/O (Input/Output) to the processor 401 and the memory 402. In some embodiments, processor 401, memory 402, and peripheral interface 403 are integrated on the same chip or circuit board; in some other embodiments, any one or two of the processor 401, the memory 402 and the peripheral interface 403 may be implemented on a separate chip or circuit board, which is not limited by this embodiment.
The Radio Frequency circuit 404 is used for receiving and transmitting RF (Radio Frequency) signals, also called electromagnetic signals. The radio frequency circuitry 404 communicates with communication networks and other communication devices via electromagnetic signals. The rf circuit 404 converts an electrical signal into an electromagnetic signal to transmit, or converts a received electromagnetic signal into an electrical signal. Optionally, the radio frequency circuit 404 includes: an antenna system, an RF transceiver, one or more amplifiers, a tuner, an oscillator, a digital signal processor, a codec chipset, a subscriber identity module card, and so forth. The radio frequency circuitry 404 may communicate with other terminals via at least one wireless communication protocol. The wireless communication protocols include, but are not limited to: metropolitan area networks, various generation mobile communication networks (2G, 3G, 4G, and 5G), wireless local area networks, and/or WiFi (Wireless Fidelity) networks. In some embodiments, the rf circuit 404 may further include NFC (Near Field Communication) related circuits, which are not limited in this application.
The display screen 405 is used to display a UI (user interface). The UI may include graphics, text, icons, video, and any combination thereof. When the display screen 405 is a touch display screen, the display screen 405 also has the ability to capture touch signals on or above the surface of the display screen 405. The touch signal may be input to the processor 401 as a control signal for processing. At this point, the display screen 405 may also be used to provide virtual buttons and/or a virtual keyboard, also referred to as soft buttons and/or a soft keyboard. In some embodiments, the display 405 may be one, providing the front panel of the terminal 400; in other embodiments, the display screen 405 may be at least two, respectively disposed on different surfaces of the terminal 400 or in a foldable design; in still other embodiments, the display 405 may be a flexible display disposed on a curved surface or a folded surface of the terminal 400. Even further, the display screen 405 may be arranged in a non-rectangular irregular pattern, i.e. a shaped screen. The Display screen 405 may be made of LCD (Liquid Crystal Display), OLED (Organic Light-Emitting Diode), and other materials.
The camera assembly 406 is used to capture images or video. Optionally, camera assembly 406 includes a front camera and a rear camera. Generally, a front camera is disposed at a front panel of the terminal, and a rear camera is disposed at a rear surface of the terminal. In some embodiments, the number of the rear cameras is at least two, and each rear camera is any one of a main camera, a depth-of-field camera, a wide-angle camera and a telephoto camera, so that the main camera and the depth-of-field camera are fused to realize a background blurring function, and the main camera and the wide-angle camera are fused to realize panoramic shooting and VR (Virtual Reality) shooting functions or other fusion shooting functions. In some embodiments, camera assembly 406 may also include a flash. The flash lamp can be a monochrome temperature flash lamp or a bicolor temperature flash lamp. The double-color-temperature flash lamp is 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 407 may include a microphone and a speaker. The microphone is used for collecting sound waves of a user and the environment, converting the sound waves into electric signals, and inputting the electric signals to the processor 401 for processing, or inputting the electric signals to the radio frequency circuit 404 for realizing voice communication. For the purpose of stereo sound collection or noise reduction, a plurality of microphones may be provided at different portions of the terminal 400. The microphone may also be an array microphone or an omni-directional acquisition microphone. The speaker is used to convert electrical signals from the processor 401 or the radio frequency circuit 404 into sound waves. The loudspeaker can be a traditional film loudspeaker or a piezoelectric ceramic loudspeaker. When the speaker is a piezoelectric ceramic speaker, the speaker can be used for purposes such as converting an electric signal into a sound wave audible to a human being, or converting an electric signal into a sound wave inaudible to a human being to measure a distance. In some embodiments, audio circuitry 407 may also include a headphone jack.
The positioning component 408 is used to locate the current geographic position of the terminal 400 for navigation or LBS (Location Based Service). The Positioning component 408 may be a Positioning component based on the GPS (Global Positioning System) of the united states, the beidou System of china, the graves System of russia, or the galileo System of the european union.
The power supply 409 is used to supply power to the various components in the terminal 400. The power source 409 may be alternating current, direct current, disposable or rechargeable. When power source 409 comprises 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, the terminal 400 also includes one or more sensors 410. The one or more sensors 410 include, but are not limited to: acceleration sensor 411, gyro sensor 412, pressure sensor 413, fingerprint sensor 414, optical sensor 415, and proximity sensor 416.
The acceleration sensor 411 may detect the magnitude of acceleration in three coordinate axes of the coordinate system established with the terminal 400. For example, the acceleration sensor 411 may be used to detect components of the gravitational acceleration in three coordinate axes. The processor 401 may control the display screen 405 to display the user interface in a landscape view or a portrait view according to the gravitational acceleration signal collected by the acceleration sensor 411. The acceleration sensor 411 may also be used for acquisition of motion data of a game or a user.
The gyro sensor 412 may detect a body direction and a rotation angle of the terminal 400, and the gyro sensor 412 may cooperate with the acceleration sensor 411 to acquire a 3D motion of the terminal 400 by the user. From the data collected by the gyro sensor 412, the processor 401 may implement the following functions: motion sensing (such as changing the UI according to a user's tilting operation), image stabilization at the time of photographing, game control, and inertial navigation.
The pressure sensor 413 may be disposed on a side bezel of the terminal 400 and/or on a lower layer of the display screen 405. When the pressure sensor 413 is disposed on the side frame of the terminal 400, a user's holding signal to the terminal 400 can be detected, and the processor 401 performs left-right hand recognition or shortcut operation according to the holding signal collected by the pressure sensor 413. When the pressure sensor 413 is arranged at the lower layer of the display screen 405, the processor 401 controls the operability control on the UI interface according to the pressure operation of the user on the display screen 405. The operability control comprises at least one of a button control, a scroll bar control, an icon control and a menu control.
The fingerprint sensor 414 is used to collect a fingerprint of the user, and the processor 401 identifies the user according to the fingerprint collected by the fingerprint sensor 414, or the fingerprint sensor 414 identifies the user according to the collected fingerprint. Upon recognizing that the user's identity is a trusted identity, processor 401 authorizes the user to perform relevant sensitive operations including unlocking the screen, viewing encrypted information, downloading software, paying, and changing settings, etc. The fingerprint sensor 414 may be disposed on the front, back, or side of the terminal 400. When a physical key or vendor Logo is provided on the terminal 400, the fingerprint sensor 414 may be integrated with the physical key or vendor Logo.
The optical sensor 415 is used to collect the ambient light intensity. In one embodiment, processor 401 may control the display brightness of display screen 405 based on the ambient light intensity collected by optical sensor 415. Specifically, when the ambient light intensity is high, the display brightness of the display screen 405 is increased; when the ambient light intensity is low, the display brightness of the display screen 405 is reduced. In another embodiment, the processor 401 may also dynamically adjust the shooting parameters of the camera assembly 406 according to the ambient light intensity collected by the optical sensor 415.
A proximity sensor 416, also known as a distance sensor, is typically disposed on the front panel of the terminal 400. The proximity sensor 416 is used to collect the distance between the user and the front surface of the terminal 400. In one embodiment, when the proximity sensor 416 detects that the distance between the user and the front surface of the terminal 400 is gradually decreased, the display screen 405 is controlled by the processor 401 to switch from the bright screen state to the dark screen state; when the proximity sensor 416 detects that the distance between the user and the front surface of the terminal 400 is gradually increased, the display screen 405 is controlled by the processor 401 to switch from the breath-screen state to the bright-screen state.
Those skilled in the art will appreciate that the configuration shown in fig. 4 is not intended to be limiting of terminal 400 and may include more or fewer components than those shown, or some components may be combined, or a different arrangement of components may be used.
In an exemplary embodiment, a storage medium comprising program code, such as a memory comprising program code, executable by a processor of an apparatus to perform the above method is also provided. Alternatively, the storage medium may be a non-transitory computer readable storage medium, which may be, for example, a ROM (Read-Only Memory), a RAM (Random Access Memory), a CD-ROM (Compact Disc Read-Only Memory), a magnetic tape, a floppy disk, an optical data storage device, and the like.
The above description is only exemplary of the present application and should not be taken as limiting, as any modification, equivalent replacement, or improvement made within the spirit and principle of the present application should be included in the protection scope of the present application.
Claims (10)
1. A method for determining dynamic reserves, the method comprising:
acquiring the pressure, the temperature and the yield of an oil well to be tested;
determining a volume factor of the crude oil in the well and determining a compressibility factor of the well based on the temperature and the pressure;
determining a flow characteristic of the well from the production, the volume factor and the compressibility factor, the flow characteristic being indicative of a flow phase in which the well is located;
when the flow characteristics are used for indicating that the flow phase of the oil well is a quasi-stable flow phase, determining a corresponding target yield of the oil well in the quasi-stable flow phase;
and determining the dynamic reserves of the oil well according to the target yield, the volume coefficient and the compression coefficient.
2. The method of claim 1, wherein determining the volume factor of the crude oil in the well based on the temperature and the pressure comprises:
according to the temperature, determining a temperature coefficient matched with the temperature;
determining the volume coefficient of crude oil in the oil well according to the temperature coefficient and the pressure by the following formula I;
the formula I is as follows: b =0.952-2.154 × 10 -4 P R +10 A
Wherein B represents the volume coefficient of the crude oil in the oil well, P R Represents the pressure and a represents the temperature coefficient.
3. The method of claim 1, wherein the determining the compressibility of the oil well comprises:
acquiring the compression coefficient of rock, the compression coefficient of crude oil and the compression coefficient of water in the oil well; and, determining the saturation of crude oil and the saturation of water in the well;
determining the compression coefficient of the oil well according to the compression coefficient of the rock, the compression coefficient of the crude oil, the compression coefficient of the water, the saturation of the crude oil and the saturation of the water by the following formula II;
the formula II is as follows: c t ＝C r +C o S o +C w S w
Wherein, C t Representing the compressibility of said well, C r Representing the compression coefficient, C, of said rock o Representing the compressibility of said crude oil, C w Represents the compressibility factor, S, of said water o Represents the saturation of the crude oil, S w Representing the saturation of said water.
4. The method of claim 1, wherein said determining flow characteristics of said well from said production, said volume factor and said compressibility factor comprises:
determining a variation of a bottom hole pressure of the oil well according to the production, the volume coefficient and the compressibility coefficient;
determining a first logarithm value corresponding to the bottom hole pressure and a second logarithm value corresponding to the bottom hole pressure according to the variation of the bottom hole pressure;
determining a flow characteristic of the well based on the first and second logarithm values.
5. The method of claim 4, wherein determining the change in the bottom hole pressure of the well based on the production, the volume factor, and the compressibility factor comprises:
obtaining the flowing time of crude oil in the oil well, the viscosity of the crude oil, the bottom hole depth of the oil well, the bottom hole permeability of the oil well, the area of a reservoir where the oil well is located, the pore volume of the reservoir where the oil well is located, the bottom hole resistance coefficient of the oil well, the shape factor of the oil well and the radius of the oil well;
determining the variation of the bottom hole pressure of the oil well according to the yield, the volume coefficient, the compression coefficient, the flow velocity and the time length of the crude oil in the oil well, the viscosity of the crude oil, the bottom hole depth of the oil well, the bottom hole permeability of the oil well, the area of a reservoir in which the oil well is positioned, the pore volume of the reservoir in which the oil well is positioned, the bottom hole resistance coefficient of the oil well, the shape factor of the oil well and the radius of the oil well by the following formula III;
the formula III is as follows:
wherein Δ p represents a change amount of a bottom hole pressure of the oil well, q represents the yield, μ represents a viscosity of the crude oil, B represents the volume coefficient, K represents a bottom hole permeability of the oil well, h represents a bottom hole depth of the oil well, a represents an area of a reservoir in which the oil well is located, S represents a bottom hole resistance coefficient of the oil well, r represents a radius of the oil well, C represents a bottom hole pressure of the oil well, and A representing the shape factor, V, of the well P Represents the pore volume, C, of the reservoir in which the well is located t Representing the compressibility of the well and t representing the length of time that the crude oil has flowed within the well.
6. The method of claim 1, wherein determining the dynamic reserve of the well based on the target production, the volume factor, and the compressibility factor comprises:
determining a volume of fracturing fluid within the well;
determining the volume of crude oil in pores of a reservoir where the oil well is located according to the target yield, the volume coefficient and the compression coefficient;
and determining the difference between the volume of the crude oil in the pores of the reservoir where the oil well is located and the volume of the fracturing fluid as the dynamic reserve of the oil well.
7. The method of claim 6, wherein determining the volume of crude oil in the pores of the reservoir in which the well is located based on the target production, the volume factor, and the compressibility comprises:
acquiring the duration of the oil well in a quasi-stable flow stage and the target pressure corresponding to the oil well in the quasi-stable flow stage;
determining the volume of crude oil in the pore space of the reservoir where the oil well is located according to the time length, the target pressure, the target yield, the volume coefficient and the compression coefficient by the following formula IV;
the formula IV is as follows:
wherein, V s Representing the volume of crude oil in the pores of the reservoir in which the well is located, q representing the target production, B representing the volume factor of crude oil in the well, C t Representing the compressibility of the well, p representing the target pressure, and t representing the time period.
8. An apparatus for determining dynamic reserves, the apparatus comprising:
the acquisition module is used for acquiring the pressure, the temperature and the yield of an oil well to be tested;
a first determination module for determining a volume factor of the crude oil in the well and determining a compressibility factor of the well based on the temperature and the pressure;
a second determination module for determining a flow characteristic of the well based on the production, the volume factor and the compressibility factor, the flow characteristic being indicative of a flow phase in which the well is located;
a third determining module, configured to determine, when the flow characteristic is used to indicate that the flow phase in which the oil well is located is a quasi-steady flow phase, a corresponding target production rate when the oil well is in the quasi-steady flow phase;
and the fourth determination module is used for determining the dynamic reserves of the oil well according to the target yield, the volume coefficient and the compression coefficient.
9. A computer device, characterized in that the computer device comprises:
a processor and a memory, the memory having stored therein at least one program code, the at least one program code being loaded and executed by the processor to perform the operations performed in the method for determining dynamic reserve of any of claims 1 to 7.
10. A computer-readable storage medium having at least one program code stored therein, the at least one program code being loaded and executed by a processor to implement the operations performed in the method for determining dynamic reserve of any of claims 1 to 7.
Priority Applications (1)
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|---|---|---|---|
| CN202110288877.5A CN115163056A (en) | 2021-03-18 | 2021-03-18 | Method and device for determining dynamic reserves, computer equipment and storage medium |
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| CN202110288877.5A CN115163056A (en) | 2021-03-18 | 2021-03-18 | Method and device for determining dynamic reserves, computer equipment and storage medium |
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