CN111305805B - Reservoir fracture imbibition quality prediction method and system - Google Patents

Reservoir fracture imbibition quality prediction method and system Download PDF

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CN111305805B
CN111305805B CN202010135002.7A CN202010135002A CN111305805B CN 111305805 B CN111305805 B CN 111305805B CN 202010135002 A CN202010135002 A CN 202010135002A CN 111305805 B CN111305805 B CN 111305805B
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王付勇
程辉
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China University of Petroleum Beijing
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Abstract

The invention provides a method and a system for predicting the seepage quality of a reservoir fracture. The method comprises the following steps: determining the fracture imbibition height of each fracture at the current imbibition time according to the capillary force of each fracture and the gravity at the last imbibition time; when the fracture imbibition height is less than or equal to the core height, obtaining the imbibition quality of the fracture at the current imbibition time according to the fracture length of the fracture, the fracture imbibition height of the fracture at the current imbibition time, the fracture number of the fracture length and the density of the wet-phase fluid; otherwise, obtaining the imbibition quality of the fracture at the current imbibition moment according to the fracture length, the core height, the fracture number of the fracture length, the wet-phase fluid density and the average tortuosity of the fracture; and predicting the imbibition quality of the core at the current imbibition time according to the imbibition quality of each fracture at the current imbibition time so as to create or adjust an oil-gas resource development scheme of the reservoir. The invention can effectively guide the development process of oil and gas resources.

Description

Reservoir fracture imbibition quality prediction method and system
Technical Field
The invention relates to the technical field of oil reservoir exploration and development, in particular to a method and a system for predicting the seepage and absorption quality of a reservoir fracture.
Background
The development of unconventional oil and gas resources such as dense gas, shale gas and the like has important significance for guaranteeing national energy safety. Different from the conventional oil and gas reservoir, the compact oil and gas reservoir has the characteristics of low pore and low permeability, complex pore throat structure, strong capillary force action and obvious spontaneous imbibition phenomenon. Large-scale hydraulic fracturing is a commonly used technical means for improving the capacity of compact reservoirs, and a large amount of fracturing fluid is injected into the reservoirs to generate artificial fractures. However, in mine applications, more than 50% of the fracturing fluid remains in the underground reservoir, and spontaneous imbibition is one of the main causes of low flowback of the fracturing fluid. Research shows that a large number of natural micro-nano cracks develop in a compact reservoir, and the natural cracks and artificial cracks generated by fracturing are intersected to form a complex crack network structure, so that research on a spontaneous imbibition mechanism of fracturing fluid in the natural/artificial cracks has great significance for development of compact gas and shale gas.
At present, the research on the spontaneous imbibition mechanism of the crack has a weighing method, a volume method, CT scanning, nuclear magnetic resonance, a neutron photography technology and the like, but the methods have the following problems: (1) the porosity of the compact sandstone is generally less than 10%, which means that the mass change of the rock core in the imbibition process is very small, namely the precision requirement on a measuring tool is very high, and the conventional measuring tool cannot achieve satisfactory precision, so that the weighing method and the volume method have large errors although the dynamic change of the imbibition mass of the rock core along with time can be researched. (2) Although the methods such as CT scanning and nuclear magnetic resonance have higher precision, the cost is high, and the dynamic change of the imbibition mass along with the time cannot be researched; although the neutron photography technology can research the dynamic change in the imbibition process, the neutron photography technology has very high requirements on experimental equipment, is very high in experimental cost, is difficult to popularize and apply, and is not beneficial to the development of oil and gas resources.
Disclosure of Invention
The embodiment of the invention mainly aims to provide a method and a system for predicting the seepage quality of reservoir fractures, so as to predict the accurate seepage quality of the fractures, reduce the prediction cost and further effectively guide the development process of oil and gas resources.
In order to achieve the above object, an embodiment of the present invention provides a method for predicting a permeability quality of a reservoir fracture, including:
acquiring capillary force of each crack and gravity of each crack at the last imbibition moment;
determining the seepage height of each crack at the current seepage moment according to the comparison result of the capillary force of each crack and the gravity at the last seepage moment;
creating a first imbibition quality prediction model and a second imbibition quality prediction model;
when the fracture imbibition height of the fracture at the current imbibition time is less than or equal to the core height, inputting the fracture length of the fracture, the fracture imbibition height of the fracture at the current imbibition time, the fracture number of the fracture length and the wet-phase fluid density into a first imbibition quality prediction model to obtain the imbibition quality of the fracture at the current imbibition time;
when the fracture imbibition height of the fracture at the current imbibition time is greater than the core height, inputting the fracture length, the core height, the fracture number of the fracture length, the wet-phase fluid density and the average tortuosity of the fracture into a second imbibition quality prediction model to obtain the imbibition quality of the fracture at the current imbibition time;
and predicting the imbibition quality of the core at the current imbibition time according to the imbibition quality of each fracture at the current imbibition time so as to create or adjust an oil-gas resource development scheme of the reservoir.
The embodiment of the invention also provides a system for predicting the seepage quality of the reservoir fracture, which comprises the following steps:
the first acquisition unit is used for acquiring the capillary force of each crack and the gravity of each crack at the last imbibition moment;
the crack imbibition height unit is used for determining the crack imbibition height of each crack at the current imbibition time according to the comparison result of the capillary force of each crack and the gravity at the last imbibition time;
the imbibition quality prediction model creating unit is used for creating a first imbibition quality prediction model and a second imbibition quality prediction model;
the fracture imbibition quality unit is used for inputting the fracture length of the fracture, the fracture imbibition height of the fracture at the current imbibition time, the fracture number of the fracture length and the density of the wet-phase fluid into a first imbibition quality prediction model when the fracture imbibition height of the fracture at the current imbibition time is less than or equal to the core height, so as to obtain the imbibition quality of the fracture at the current imbibition time; when the fracture imbibition height of the fracture at the current imbibition time is greater than the core height, inputting the fracture length, the core height, the fracture number of the fracture length, the wet-phase fluid density and the average tortuosity of the fracture into a second imbibition quality prediction model to obtain the imbibition quality of the fracture at the current imbibition time;
and the prediction unit is used for predicting the imbibition quality of the rock core at the current imbibition time according to the imbibition quality of each fracture at the current imbibition time so as to create or adjust an oil and gas resource development scheme of the reservoir.
The embodiment of the invention also provides computer equipment which comprises a memory, a processor and a computer program stored on the memory and operated on the processor, wherein the processor realizes the steps of the reservoir fracture imbibition quality prediction method when executing the computer program.
Embodiments of the present invention further provide a computer-readable storage medium, on which a computer program is stored, where the computer program, when executed by a processor, implements the steps of the method for predicting the imbibition quality of a reservoir fracture.
To sum up, the method and the system for predicting the permeability quality of the reservoir fractures in the embodiment of the invention firstly determine the fracture permeability height of each fracture at the current permeability moment according to the comparison result of the capillary force of each fracture and the gravity at the previous permeability moment, then determine the permeability quality of each fracture at the current permeability moment according to the comparison result of the fracture permeability height and the core height, and finally predict the permeability quality of the core at the current permeability moment according to the permeability quality of each fracture at the current permeability moment so as to create or adjust an oil and gas resource development scheme of the reservoir.
Drawings
In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings used 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 invention, and it is obvious for those skilled in the art that other drawings can be obtained based on these drawings without creative efforts.
FIG. 1 is a flow chart of a reservoir fracture imbibition quality prediction method in an embodiment of the invention;
FIG. 2 is a schematic illustration of spontaneous imbibition of a wet-phase fluid in a gas-saturated fractured core in an embodiment of the invention;
FIG. 3 is a schematic diagram of a theoretical model of a fractured core comprising a cluster of tortuous slab fractures in an embodiment of the invention;
FIG. 4 is a schematic illustration of spontaneous imbibition of a wet-phase fluid within a single fracture in an embodiment of the invention;
FIG. 5 is a schematic cross-sectional view of a core containing a plurality of fractures according to an embodiment of the present disclosure;
FIG. 6 is a graphical representation of the imbibition mass and imbibition saturation of a core over time for an example of the invention;
FIG. 7 is a block diagram of a reservoir fracture imbibition quality prediction system in an embodiment of the invention;
fig. 8 is a block diagram of a computer device in the embodiment of the present invention.
Detailed Description
The technical solutions in the embodiments of the present invention will be clearly and completely described below with reference to the drawings in the embodiments of the present invention, and it is obvious that the described embodiments are only a part of the embodiments of the present invention, and not all of the embodiments. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present invention.
As will be appreciated by one skilled in the art, embodiments of the present invention may be embodied as a system, apparatus, device, method, or computer program product. Accordingly, the present disclosure may be embodied in the form of: entirely hardware, entirely software (including firmware, resident software, micro-code, etc.), or a combination of hardware and software.
In view of the low precision and high cost of the prior art, which are not beneficial to the development of oil and gas resources, the embodiment of the invention provides a reservoir fracture imbibition quality prediction method and a reservoir fracture imbibition quality prediction system, which can predict the accurate fracture imbibition quality, reduce the prediction cost and further effectively guide the development process of the oil and gas resources. The present invention will be described in detail below with reference to the accompanying drawings.
FIG. 1 is a flow chart of a reservoir fracture imbibition quality prediction method in an embodiment of the invention. As shown in fig. 1, the method for predicting the seepage quality of the reservoir fracture comprises the following steps:
s101: and acquiring the capillary force of each crack and the gravity of each crack at the last imbibition moment.
Before executing S101, the method further includes:
the capillary force of each crack is determined from the crack length, surface tension and contact angle of each crack.
The capillary force of each fracture can be determined by the following formula:
Figure BDA0002397022400000041
wherein p is the capillary force of the fracture with fracture length l, and the unit is N; l is the crack length, n is the ratio of the opening to the length of the crack, σ is the surface tension, and θ is the contact angle.
And determining the gravity of each crack at the last imbibition moment according to the imbibition height of each crack at the last imbibition moment and the density of the wet-phase fluid.
The gravity of each fracture at the last imbibition time can be determined by the following formula:
Figure BDA0002397022400000042
wherein G ist-ΔtThe unit is N, and the gravity of the crack with the crack length of l at the last imbibition time (t-delta t imbibition time); rho is the density of the wet phase fluid, g is the acceleration of gravity,
Figure BDA0002397022400000043
the unit is m, and the fracture imbibition height of the fracture with the fracture length of l at the last imbibition time (t-delta t imbibition time); t is imbibition time, and the unit can be s or min; Δ t is a time step and can be in units of s or min. Fracture imbibition height of fracture with fracture length l at initial moment
Figure BDA0002397022400000044
Equal to 0.
S102: and determining the fracture imbibition height of each fracture at the current imbibition moment according to the comparison result of the capillary force of each fracture and the gravity at the last imbibition moment.
In one embodiment, S102 includes:
when the capillary force of the crack is smaller than the gravity of the crack at the last imbibition time, taking the fracture imbibition height of the crack at the last imbibition time as the fracture imbibition height of the crack at the current imbibition time:
when p < Gt-ΔtWhen the temperature of the water is higher than the set temperature,
Figure BDA0002397022400000045
Figure BDA0002397022400000046
the unit is m, which is the fracture imbibition height of the fracture with the fracture length l at the current imbibition time (time t).
The first physical property parameters include surface tension, contact angle, wet phase fluid viscosity, and average tortuosity. When the capillary force of the crack is equal to the gravity of the crack at the last imbibition moment, determining the fracture imbibition height of each crack at the current imbibition moment according to the obtained current imbibition moment, the first physical property parameter and the crack length of each crack:
when p ═ Gt-ΔtWhen the temperature of the water is higher than the set temperature,
Figure BDA0002397022400000051
wherein,
Figure BDA0002397022400000052
the fracture imbibition height of the fracture with the fracture length l at the current imbibition time (time t),
Figure BDA0002397022400000053
Figure BDA0002397022400000054
μ is the wet phase fluid viscosity and τ is the average tortuosity.
S103: a first imbibition quality prediction model and a second imbibition quality prediction model are created.
S104: and when the fracture imbibition height of the fracture at the current imbibition time is less than or equal to the core height, inputting the fracture length of the fracture, the fracture imbibition height of the fracture at the current imbibition time, the fracture number of the fracture length and the wet-phase fluid density into a first imbibition quality prediction model to obtain the imbibition quality of the fracture at the current imbibition time.
In one embodiment, the first imbibition quality prediction model is as follows:
Figure BDA0002397022400000055
wherein M isG(l) A crack having a crack length of l: (
Figure BDA0002397022400000056
Time) the imbibition mass at the current imbibition time in g or kg, ρ is the wet-phase fluid density, and n (l) is the fracture number for fracture length l.
S105: and when the fracture imbibition height of the fracture at the current imbibition time is greater than the core height, inputting the fracture length, the core height, the fracture number of the fracture length, the wet-phase fluid density and the average tortuosity of the fracture into a second imbibition quality prediction model to obtain the imbibition quality of the fracture at the current imbibition time.
In one embodiment, the second imbibition quality prediction model is as follows:
Figure BDA0002397022400000057
wherein,
Figure BDA0002397022400000058
a crack having a crack length of l: (
Figure BDA0002397022400000059
Time) the imbibition mass at the current imbibition time in g or kg; h is the core height in cm.
S106: and predicting the imbibition quality of the core at the current imbibition time according to the imbibition quality of each fracture at the current imbibition time so as to create or adjust an oil-gas resource development scheme of the reservoir.
The method for predicting the seepage quality of the reservoir fracture shown in the figure 1 is suitable for compact sandstone and shale, wherein the fracture seepage height is the seepage height of the fracture under the condition of considering gravity, and the seepage quality is the seepage quality under the condition of considering gravity. As can be seen from the process shown in fig. 1, the method for predicting the permeability quality of the reservoir fracture according to the embodiment of the present invention determines the fracture permeability height of each fracture at the current permeability time according to the comparison result between the capillary force of each fracture and the gravity at the previous permeability time, determines the permeability quality of each fracture at the current permeability time according to the comparison result between the fracture permeability height and the core height, and predicts the permeability quality of the core at the current permeability time according to the permeability quality of each fracture at the current permeability time to create or adjust an oil and gas resource development scheme of the reservoir, so that the accurate fracture permeability quality can be predicted, the prediction cost can be reduced, and the development process of the oil and gas resource can be further effectively guided.
Before executing S101, the method further includes: creating a crack number model; acquiring a second physical parameter; and inputting each crack length and the second physical parameter into the crack number model to obtain the crack number of each crack length.
In one embodiment, the second physical parameter includes: core cross section, fractal dimension, maximum fracture length, minimum fracture length, fracture porosity, and fracture length step length. The fracture number model is as follows:
Figure BDA0002397022400000061
wherein n (l) is the number of cracks of the crack length l, l is the crack length, AfIs the cross section of the core, n is the ratio of the opening degree of the crack to the length, DfIs fractal dimension,/maxTo maximum crack length, /)minIs the minimum crack length, phifFor fracture porosity,. DELTA.l is the fracture length step in μm.
Table 1 shows physical property parameters. As shown in Table 1, the physical properties of one example were as follows:
TABLE 1
Figure BDA0002397022400000062
Figure BDA0002397022400000071
Wherein the cross section of the core is
Figure BDA0002397022400000072
In one embodiment, the imbibition saturation of the core at the current imbibition time can be determined according to the imbibition quality of the core at the current imbibition time, and the imbibition saturation can effectively guide the development process of oil and gas resources:
Figure BDA0002397022400000073
wherein R isGThe unit is the imbibition saturation of the rock core at the current imbibition time;
Figure BDA0002397022400000074
the unit is the imbibition mass of the rock core at the current imbibition moment and is g or kg; d is the core diameter.
FIG. 2 is a schematic illustration of spontaneous imbibition of a wet phase fluid in a gas saturated fracture-type core in an embodiment of the invention. FIG. 3 is a schematic diagram of a theoretical model of a fractured core comprising a cluster of tortuous slab fractures in an embodiment of the invention. FIG. 4 is a schematic diagram of spontaneous imbibition of a wet phase fluid within a single fracture in an embodiment of the invention, and is also an enlarged view of the box in FIG. 3.
As shown in fig. 2, the flow of the wet phase fluid 3 within the fracture 2 is very similar to the flow between the plates, thus assuming a large number of natural fractures within the core 1 as a cluster of tortuous plate fractures with fractal distribution and not intersecting each other, as shown in fig. 3.
As shown in fig. 4, the viscosity and density of the natural gas 4 are negligible compared to the wet phase fluid 3, and the spontaneous imbibition flow in a single fracture can be expressed as:
Figure BDA0002397022400000075
wherein q is the spontaneous imbibition flow in a single fracture in mm3S; a is the crack opening degree in mum; l is the crack length in μm; l isfThe length of the tortuosity from the imbibition front edge to the bottom surface of the rock core is m; l issThe length of a straight line from the imbibition front edge to the bottom surface of the rock core (fracture imbibition height) is m; μ is the wet phase fluid viscosity in units of mPa · s; sigma is the surface tension of natural gas and wet phase fluid, and the unit is mN/m; (ii) a θ is the contact angle in °; rho is the wet-phase fluid density in kg/m3(ii) a g is the acceleration of gravity in m/s2. Equation (1) can be written as a differential form as follows:
Figure BDA0002397022400000076
the relationship between the tortuosity length of the imbibition front to the core floor and the fracture imbibition height can be expressed as:
Lf＝τLs。 (3)
wherein tau is the average tortuosity of the crack and is dimensionless. The formula (3) can be substituted for the formula (2):
Figure BDA0002397022400000081
equation (4) can be written as follows:
Figure BDA0002397022400000082
the solution of equation (5) is:
Figure BDA0002397022400000083
wherein a is nl, n is the ratio of the opening degree of the crack to the length, and is dimensionless, therefore
Figure BDA0002397022400000084
Figure BDA0002397022400000085
Figure BDA0002397022400000086
The fracture imbibition height of a single fracture; introducing a lambertian function (Lambert function) w (x) may result in an explicit solution of equation (6):
Figure BDA0002397022400000087
Figure BDA0002397022400000088
mass m of single crack imbibition at time tGComprises the following steps:
Figure BDA0002397022400000089
wherein m isGThe unit of (b) is g or kg.
FIG. 5 is a cross-sectional schematic view of a core containing a plurality of fractures according to an embodiment of the present disclosure. As shown in FIG. 5, the core contains a large number of natural fractures, and a representative unit A is selected from the cross section of the coreuTo study, assume representative Unit AuThe internal crack length follows fractal distribution:
Figure BDA00023970224000000810
wherein N (l ≧ zeta) is the number of cracks whose length is greater than zeta, lmaxMaximum crack length in μm; dfFractal dimension, dimensionless. Taking the derivative of both ends of equation (10) with respect to l yields the following equation:
Figure BDA00023970224000000811
thus representative Unit AuTotal pore area A ofpCan be calculated to yield:
Figure BDA0002397022400000091
further representative Unit AuCan be calculated as:
Figure BDA0002397022400000092
wherein phifIs the crack porosity in%; lminIs the minimum crack length in μm. Core Cross section AfThe total number of cracks in (a) can be calculated as:
Figure BDA0002397022400000093
wherein A isfIs the cross section of the core and has the unit of cm2，AuAnd ApAll units of (are cm)2；NfAnd the number of cracks with the length larger than l in the cross section of the core is (more than or equal to l). Derivation of equation (14) for l can be found:
Figure BDA0002397022400000094
the number of fractures n (l) with a fracture length l can be calculated according to equation (14):
Figure BDA0002397022400000095
for the whole core, the fracture imbibition mass with length l is the product of the imbibition mass of a single fracture and the number of the single fracture. The fracture imbibition quality of the core consists of two parts of imbibition stopping and imbibition not stopping. The seepage quality of the crack when the seepage stops is as follows:
Figure BDA0002397022400000096
wherein L iseThe expression is as follows for the imbibition equilibrium height in m:
Figure BDA0002397022400000101
therefore, the temperature of the molten metal is controlled,
Figure BDA0002397022400000102
the seepage quality of the cracks when seepage is not stopped is as follows:
Figure BDA0002397022400000103
therefore, the temperature of the molten metal is controlled,
Figure BDA0002397022400000104
the imbibition mass of the core can be expressed as:
Figure BDA0002397022400000105
wherein lcThe critical crack length, which represents the length of the crack at which the imbibition just stopped at time t, is expressed in μm, and is expressed as follows:
Figure BDA0002397022400000106
the concrete flow of the reservoir fracture imbibition quality prediction method is as follows:
1. creating a crack number model; acquiring a second physical parameter; and inputting each crack length and the second physical parameter into the crack number model to obtain the crack number of each crack length.
2. The capillary force of each crack is determined from the crack length, surface tension and contact angle of each crack. And determining the gravity of each crack at the last imbibition moment according to the imbibition height of each crack at the last imbibition moment and the density of the wet-phase fluid.
3. And acquiring the capillary force of each crack and the gravity of each crack at the last imbibition moment.
4. And when the capillary force of the crack is smaller than the gravity of the crack at the last imbibition time, taking the fracture imbibition height of the crack at the last imbibition time as the fracture imbibition height of the crack at the current imbibition time. And when the capillary force of the crack is equal to the gravity of the crack at the last imbibition moment, determining the fracture imbibition height of each crack at the current imbibition moment according to the obtained current imbibition moment, the first physical property parameter and the crack length of each crack.
5. A first imbibition quality prediction model and a second imbibition quality prediction model are created.
6. And when the fracture imbibition height of the fracture at the current imbibition time is less than or equal to the core height, inputting the fracture length of the fracture, the fracture imbibition height of the fracture at the current imbibition time, the fracture number of the fracture length and the wet-phase fluid density into a first imbibition quality prediction model to obtain the imbibition quality of the fracture at the current imbibition time.
7. And when the fracture imbibition height of the fracture at the current imbibition time is greater than the core height, inputting the fracture length, the core height, the fracture number of the fracture length, the wet-phase fluid density and the average tortuosity of the fracture into a second imbibition quality prediction model to obtain the imbibition quality of the fracture at the current imbibition time.
8. And predicting the imbibition quality of the core at the current imbibition time according to the imbibition quality of each fracture at the current imbibition time so as to create or adjust an oil-gas resource development scheme of the reservoir.
9. And determining the imbibition saturation of the core at the current imbibition time according to the imbibition quality of the core at the current imbibition time so as to create or adjust an oil-gas resource development scheme of the reservoir.
FIG. 6 is a graphical representation of the imbibition mass and imbibition saturation of a core over time for an example of the invention. As shown in fig. 6, the abscissa in fig. 6 is time in units of min; the ordinate is the imbibition mass and the imbibition saturation in g and% respectively.
To sum up, the reservoir fracture imbibition quality prediction method of the embodiment of the invention determines the fracture imbibition height of each fracture at the current imbibition time according to the comparison result of the capillary force of each fracture and the gravity at the previous imbibition time, determines the imbibition quality of each fracture at the current imbibition time according to the comparison result of the fracture imbibition height and the core height, and predicts the imbibition quality of the core at the current imbibition time according to the imbibition quality of each fracture at the current imbibition time to create or adjust the oil and gas resource development scheme of the reservoir, so that the accurate fracture imbibition quality can be predicted, the prediction cost is reduced, and the development process of the oil and gas resource is further effectively guided.
Based on the same inventive concept, the embodiment of the invention also provides a system for predicting the permeability quality of the reservoir fracture, and as the problem solving principle of the system is similar to that of a method for predicting the permeability quality of the reservoir fracture, the implementation of the system can refer to the implementation of the method, and repeated parts are not repeated.
FIG. 7 is a block diagram of a reservoir fracture imbibition quality prediction system in an embodiment of the invention. As shown in fig. 7, the reservoir fracture imbibition quality prediction system includes:
the first acquisition unit is used for acquiring the capillary force of each crack and the gravity of each crack at the last imbibition moment;
the crack imbibition height unit is used for determining the crack imbibition height of each crack at the current imbibition time according to the comparison result of the capillary force of each crack and the gravity at the last imbibition time;
the imbibition quality prediction model creating unit is used for creating a first imbibition quality prediction model and a second imbibition quality prediction model;
the fracture imbibition quality unit is used for inputting the fracture length of the fracture, the fracture imbibition height of the fracture at the current imbibition time, the fracture number of the fracture length and the density of the wet-phase fluid into a first imbibition quality prediction model when the fracture imbibition height of the fracture at the current imbibition time is less than or equal to the core height, so as to obtain the imbibition quality of the fracture at the current imbibition time; when the fracture imbibition height of the fracture at the current imbibition time is greater than the core height, inputting the fracture length, the core height, the fracture number of the fracture length, the wet-phase fluid density and the average tortuosity of the fracture into a second imbibition quality prediction model to obtain the imbibition quality of the fracture at the current imbibition time;
and the prediction unit is used for predicting the imbibition quality of the rock core at the current imbibition time according to the imbibition quality of each fracture at the current imbibition time so as to create or adjust an oil and gas resource development scheme of the reservoir.
In one embodiment, the method further comprises the following steps:
a capillary force determination unit for determining a capillary force of each crack according to the crack length, the surface tension and the contact angle of each crack;
and the gravity determining unit is used for determining the gravity of each crack at the last imbibition moment according to the fracture imbibition height and the wet-phase fluid density of each crack at the last imbibition moment.
In one embodiment, the fracture imbibition height unit is specifically configured to:
when the capillary force of the crack is smaller than the gravity of the crack at the last imbibition time, taking the fracture imbibition height of the crack at the last imbibition time as the fracture imbibition height of the crack at the current imbibition time;
and when the capillary force of the crack is equal to the gravity of the crack at the last imbibition moment, determining the fracture imbibition height of each crack at the current imbibition moment according to the obtained current imbibition moment, the first physical property parameter and the crack length of each crack.
In one embodiment, the method further comprises the following steps:
a fracture number model creation unit for creating a fracture number model;
the second acquiring unit is used for acquiring a second physical parameter;
and the crack number unit is used for inputting each crack length and the second physical parameter into the crack number model to obtain the crack number of each crack length.
To sum up, the reservoir fracture imbibition quality prediction system of the embodiment of the invention determines the fracture imbibition height of each fracture at the current imbibition time according to the comparison result of the capillary force of each fracture and the gravity at the previous imbibition time, determines the imbibition quality of each fracture at the current imbibition time according to the comparison result of the fracture imbibition height and the core height, and predicts the imbibition quality of the core at the current imbibition time according to the imbibition quality of each fracture at the current imbibition time to create or adjust an oil and gas resource development scheme of the reservoir, so that the accurate fracture imbibition quality can be predicted, the prediction cost is reduced, and the development process of oil and gas resources is further effectively guided.
The embodiment of the invention also provides a specific implementation mode of computer equipment capable of realizing all the steps in the reservoir fracture imbibition quality prediction method in the embodiment. Fig. 8 is a block diagram of a computer device in an embodiment of the present invention, and referring to fig. 8, the computer device specifically includes the following:
a processor (processor)801 and a memory (memory) 802.
The processor 801 is configured to call a computer program in the memory 802, and the processor executes the computer program to implement all the steps of the method for predicting the permeability quality of the reservoir fracture in the above embodiment, for example, the processor executes the computer program to implement the following steps:
acquiring capillary force of each crack and gravity of each crack at the last imbibition moment;
determining the seepage height of each crack at the current seepage moment according to the comparison result of the capillary force of each crack and the gravity at the last seepage moment;
creating a first imbibition quality prediction model and a second imbibition quality prediction model;
when the fracture imbibition height of the fracture at the current imbibition time is less than or equal to the core height, inputting the fracture length of the fracture, the fracture imbibition height of the fracture at the current imbibition time, the fracture number of the fracture length and the wet-phase fluid density into a first imbibition quality prediction model to obtain the imbibition quality of the fracture at the current imbibition time;
when the fracture imbibition height of the fracture at the current imbibition time is greater than the core height, inputting the fracture length, the core height, the fracture number of the fracture length, the wet-phase fluid density and the average tortuosity of the fracture into a second imbibition quality prediction model to obtain the imbibition quality of the fracture at the current imbibition time;
and predicting the imbibition quality of the core at the current imbibition time according to the imbibition quality of each fracture at the current imbibition time so as to create or adjust an oil-gas resource development scheme of the reservoir.
To sum up, the computer device of the embodiment of the invention determines the fracture imbibition height of each fracture at the current imbibition time according to the comparison result of the capillary force of each fracture and the gravity at the last imbibition time, determines the imbibition quality of each fracture at the current imbibition time according to the comparison result of the fracture imbibition height and the core height, and predicts the imbibition quality of the core at the current imbibition time according to the imbibition quality of each fracture at the current imbibition time to create or adjust an oil and gas resource development scheme of a reservoir, so that the accurate fracture imbibition quality can be predicted, the prediction cost is reduced, and the development process of the oil and gas resource is further effectively guided.
An embodiment of the present invention further provides a computer-readable storage medium capable of implementing all the steps in the method for predicting the imbibition quality of a reservoir fracture in the foregoing embodiment, where the computer-readable storage medium stores a computer program, and the computer program, when executed by a processor, implements all the steps in the method for predicting the imbibition quality of a reservoir fracture in the foregoing embodiment, for example, the processor implements the following steps when executing the computer program:
acquiring capillary force of each crack and gravity of each crack at the last imbibition moment;
determining the seepage height of each crack at the current seepage moment according to the comparison result of the capillary force of each crack and the gravity at the last seepage moment;
creating a first imbibition quality prediction model and a second imbibition quality prediction model;
when the fracture imbibition height of the fracture at the current imbibition time is less than or equal to the core height, inputting the fracture length of the fracture, the fracture imbibition height of the fracture at the current imbibition time, the fracture number of the fracture length and the wet-phase fluid density into a first imbibition quality prediction model to obtain the imbibition quality of the fracture at the current imbibition time;
when the fracture imbibition height of the fracture at the current imbibition time is greater than the core height, inputting the fracture length, the core height, the fracture number of the fracture length, the wet-phase fluid density and the average tortuosity of the fracture into a second imbibition quality prediction model to obtain the imbibition quality of the fracture at the current imbibition time;
and predicting the imbibition quality of the core at the current imbibition time according to the imbibition quality of each fracture at the current imbibition time so as to create or adjust an oil-gas resource development scheme of the reservoir.
To sum up, the computer-readable storage medium of the embodiment of the present invention determines the fracture imbibition height of each fracture at the current imbibition time according to the comparison result between the capillary force of each fracture and the gravity at the previous imbibition time, determines the imbibition quality of each fracture at the current imbibition time according to the comparison result between the fracture imbibition height and the core height, and predicts the imbibition quality of the core at the current imbibition time according to the imbibition quality of each fracture at the current imbibition time to create or adjust the oil and gas resource development scheme of the reservoir, so that the accurate fracture imbibition quality can be predicted, the prediction cost is reduced, and the development process of the oil and gas resource is further effectively guided.
The above-mentioned embodiments are intended to illustrate the objects, technical solutions and advantages of the present invention in further detail, and it should be understood that the above-mentioned embodiments are only exemplary embodiments of the present invention, and are not intended to limit the scope of the present invention, and any modifications, equivalent substitutions, improvements and the like made within the spirit and principle of the present invention should be included in the scope of the present invention.
Those of skill in the art will further appreciate that the various illustrative logical blocks, units, and steps described in connection with the embodiments disclosed herein may be implemented as electronic hardware, computer software, or combinations of both. To clearly illustrate the interchangeability of hardware and software, various illustrative components, elements, and steps have been described above generally in terms of their functionality. Whether such functionality is implemented as hardware or software depends upon the particular application and design requirements of the overall system. Skilled artisans may implement the described functionality in varying ways for each particular application, but such implementation decisions should not be interpreted as causing a departure from the scope of the present embodiments.
The various illustrative logical blocks, or elements, or devices described in connection with the embodiments disclosed herein may be implemented or performed with a general purpose processor, a digital signal processor, an Application Specific Integrated Circuit (ASIC), a field programmable gate array or other programmable logic device, discrete gate or transistor logic, discrete hardware components, or any combination thereof designed to perform the functions described herein. A general-purpose processor may be a microprocessor, but in the alternative, the processor may be any conventional processor, controller, microcontroller, or state machine. A processor may also be implemented as a combination of computing devices, e.g., a digital signal processor and a microprocessor, a plurality of microprocessors, one or more microprocessors in conjunction with a digital signal processor core, or any other similar configuration.
The steps of a method or algorithm described in connection with the embodiments disclosed herein may be embodied directly in hardware, in a software module executed by a processor, or in a combination of the two. A software module may be stored in RAM memory, flash memory, ROM memory, EPROM memory, EEPROM memory, registers, hard disk, a removable disk, a CD-ROM, or any other form of storage medium known in the art. For example, a storage medium may be coupled to the processor such the processor can read information from, and write information to, the storage medium. In the alternative, the storage medium may be integral to the processor. The processor and the storage medium may reside in an ASIC, which may be located in a user terminal. In the alternative, the processor and the storage medium may reside in different components in a user terminal.
In one or more exemplary designs, the functions described above in connection with the embodiments of the invention may be implemented in hardware, software, firmware, or any combination of the three. If implemented in software, the functions may be stored on or transmitted over as one or more instructions or code on a computer-readable medium. Computer-readable media includes both computer storage media and communication media that facilitate transfer of a computer program from one place to another. Storage media may be any available media that can be accessed by a general purpose or special purpose computer. For example, such computer-readable media can include, but is not limited to, RAM, ROM, EEPROM, CD-ROM or other optical disk storage, magnetic disk storage or other magnetic storage devices, or any other medium which can be used to carry or store program code in the form of instructions or data structures and which can be read by a general-purpose or special-purpose computer, or a general-purpose or special-purpose processor. Additionally, any connection is properly termed a computer-readable medium, and, thus, is included if the software is transmitted from a website, server, or other remote source via a coaxial cable, fiber optic cable, twisted pair, Digital Subscriber Line (DSL), or wirelessly, e.g., infrared, radio, and microwave. Such discs (disk) and disks (disc) include compact disks, laser disks, optical disks, DVDs, floppy disks and blu-ray disks where disks usually reproduce data magnetically, while disks usually reproduce data optically with lasers. Combinations of the above may also be included in the computer-readable medium.

Claims (10)

1. A reservoir fracture imbibition quality prediction method is characterized by comprising the following steps:
acquiring capillary force of each crack and gravity of each crack at the last imbibition moment;
determining the seepage height of each crack at the current seepage moment according to the comparison result of the capillary force of each crack and the gravity at the last seepage moment;
creating a first imbibition quality prediction model and a second imbibition quality prediction model;
when the fracture imbibition height of the fracture at the current imbibition time is less than or equal to the core height, inputting the fracture length of the fracture, the fracture imbibition height of the fracture at the current imbibition time, the fracture number of the fracture length and the density of the wet-phase fluid into the first imbibition quality prediction model to obtain the imbibition quality of the fracture at the current imbibition time;
when the fracture imbibition height of the fracture at the current imbibition time is greater than the core height, inputting the fracture length, the core height, the fracture number of the fracture length, the wet-phase fluid density and the average tortuosity of the fracture into the second imbibition quality prediction model to obtain the imbibition quality of the fracture at the current imbibition time;
and predicting the imbibition quality of the core at the current imbibition time according to the imbibition quality of each fracture at the current imbibition time so as to create or adjust an oil-gas resource development scheme of the reservoir.
2. The method for predicting the seepage quality of the reservoir fractures according to claim 1, further comprising:
determining the capillary force of each crack according to the crack length, the surface tension and the contact angle of each crack;
and determining the gravity of each crack at the last imbibition moment according to the fracture imbibition height of each crack at the last imbibition moment and the density of the wet-phase fluid.
3. The reservoir fracture imbibition quality prediction method of claim 2, wherein determining the fracture imbibition height of each fracture at the current imbibition time comprises:
when the capillary force of the crack is smaller than the gravity of the crack at the last imbibition time, taking the fracture imbibition height of the crack at the last imbibition time as the fracture imbibition height of the crack at the current imbibition time;
when the capillary force of the crack is equal to the gravity of the crack at the last imbibition time, determining the fracture imbibition height of each crack at the current imbibition time according to the obtained current imbibition time, the first physical property parameter and the crack length of each crack;
wherein the first physical property parameter comprises surface tension, contact angle, wet phase fluid viscosity, and the average tortuosity.
4. The method for predicting the seepage quality of the reservoir fractures according to claim 1, further comprising:
creating a crack number model;
acquiring a second physical parameter; wherein the second physical parameter comprises: the cross section of the rock core, the fractal dimension, the maximum fracture length, the minimum fracture length, the fracture porosity and the fracture length step length;
and inputting each crack length and the second physical parameter into the crack number model to obtain the crack number of each crack length.
5. A reservoir fracture imbibition quality prediction system, comprising:
the first acquisition unit is used for acquiring the capillary force of each crack and the gravity of each crack at the last imbibition moment;
the crack imbibition height unit is used for determining the crack imbibition height of each crack at the current imbibition time according to the comparison result of the capillary force of each crack and the gravity at the last imbibition time;
the imbibition quality prediction model creating unit is used for creating a first imbibition quality prediction model and a second imbibition quality prediction model;
the fracture imbibition quality unit is used for inputting the fracture length of the fracture, the fracture imbibition height of the fracture at the current imbibition time, the fracture number of the fracture length and the density of the wet-phase fluid into the first imbibition quality prediction model when the fracture imbibition height of the fracture at the current imbibition time is less than or equal to the core height, so as to obtain the imbibition quality of the fracture at the current imbibition time; when the fracture imbibition height of the fracture at the current imbibition time is greater than the core height, inputting the fracture length, the core height, the fracture number of the fracture length, the wet-phase fluid density and the average tortuosity of the fracture into the second imbibition quality prediction model to obtain the imbibition quality of the fracture at the current imbibition time;
and the prediction unit is used for predicting the imbibition quality of the rock core at the current imbibition time according to the imbibition quality of each fracture at the current imbibition time so as to create or adjust an oil and gas resource development scheme of the reservoir.
6. The reservoir fracture imbibition quality prediction system of claim 5, further comprising:
a capillary force determination unit for determining a capillary force of each crack according to the crack length, the surface tension and the contact angle of each crack;
and the gravity determining unit is used for determining the gravity of each crack at the last imbibition moment according to the fracture imbibition height of each crack at the last imbibition moment and the density of the wet-phase fluid.
7. A reservoir fracture imbibition quality prediction system as defined in claim 6, wherein the fracture imbibition height unit is specifically configured to:
when the capillary force of the crack is smaller than the gravity of the crack at the last imbibition time, taking the fracture imbibition height of the crack at the last imbibition time as the fracture imbibition height of the crack at the current imbibition time;
when the capillary force of the crack is equal to the gravity of the crack at the last imbibition time, determining the fracture imbibition height of each crack at the current imbibition time according to the obtained current imbibition time, the first physical property parameter and the crack length of each crack;
wherein the first physical property parameter comprises surface tension, contact angle, wet phase fluid viscosity, and the average tortuosity.
8. The reservoir fracture imbibition quality prediction system of claim 5, further comprising:
a fracture number model creation unit for creating a fracture number model;
the second acquiring unit is used for acquiring a second physical parameter; wherein the second physical parameter comprises: the cross section of the rock core, the fractal dimension, the maximum fracture length, the minimum fracture length, the fracture porosity and the fracture length step length;
and the crack number unit is used for inputting each crack length and the second physical parameter into the crack number model to obtain the crack number of each crack length.
9. A computer device comprising a memory, a processor and a computer program stored on the memory and executed on the processor, wherein the processor when executing the computer program implements the steps of the method of reservoir fracture imbibition quality prediction of any one of claims 1 to 4.
10. A computer-readable storage medium, having stored thereon a computer program, when being executed by a processor, for carrying out the steps of the method for reservoir fracture imbibition quality prediction according to any one of claims 1 to 4.
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