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CN111274528B - Reservoir fracture imbibition quality prediction method and system - Google Patents

Reservoir fracture imbibition quality prediction method and system Download PDF

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CN111274528B
CN111274528B CN202010135004.6A CN202010135004A CN111274528B CN 111274528 B CN111274528 B CN 111274528B CN 202010135004 A CN202010135004 A CN 202010135004A CN 111274528 B CN111274528 B CN 111274528B
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CN111274528A (en
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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 moment; 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; otherwise, 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 method can quickly predict the accurate seepage quality of the crack.

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.
In addition, sandstone pores (matrix) are often assumed in the prior art as a cluster of capillaries, and the flow in the fracture is assumed to be flow between the plates. However, the spontaneous imbibition rule of the crack and the matrix is obviously different, and errors can be brought by describing the fracture imbibition by using a capillary imbibition model.
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 rapidly 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:
determining the fracture imbibition height of each fracture at the current imbibition moment according to the obtained current imbibition moment, the first physical property parameter and the fracture length of each fracture;
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 crack imbibition height unit is used for determining the crack 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;
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.
The reservoir fracture imbibition quality prediction method and system firstly determine the fracture imbibition height of each fracture at the current imbibition time, then determine 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 finally predict 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 the 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 mass prediction method (without accounting for gravity) 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 (without regard to gravity);
FIG. 7 is a graph showing the variation of fracture imbibition height over time for both the prior art and the present example (without regard to gravity);
FIG. 8 is a block diagram of a reservoir fracture imbibition quality prediction system (without regard to gravity) in an embodiment of the invention;
fig. 9 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 rapidly 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 mass prediction method (without regard to gravity) in an embodiment of the invention. As shown in fig. 1, the reservoir fracture imbibition quality prediction method (without considering gravity) includes:
s101: and determining the fracture imbibition height of each fracture at the current imbibition moment according to the obtained current imbibition moment, the first physical property parameter and the fracture length of each fracture.
In one embodiment, the first physical property parameter comprises surface tension, contact angle, wet phase fluid viscosity, and average tortuosity. The fracture imbibition height of each fracture (when gravity is not considered) at the current imbibition time can be determined by the following formula:
Figure BDA0002397022590000041
wherein L issIs a crack of length l (irrespective of gravity)) The fracture imbibition height at the current imbibition time (time t), n is the ratio of the opening degree of the fracture to the length, l is the fracture length, σ is the surface tension, θ is the contact angle, μ is the wet-phase fluid viscosity, τ is the average tortuosity, and t is the imbibition time, and the unit can be s or min.
S102: a first imbibition quality prediction model and a second imbibition quality prediction model are created.
S103: 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:
M(l)＝nl2ρLsn(l)；
wherein M (L) is a fracture having a fracture length L (L without taking gravity into account)sNot more than H), the unit is kg; ρ is the wet phase fluid density and n (l) is the number of fractures for the fracture length l.
S104: 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:
Meq(l)＝ρnl2τHn(l)；
wherein M iseq(l) Is a fracture of length L (L without regard to gravity)sWhen is more than H), the unit of the imbibition mass at the current imbibition time is g or kg; h is the core height in cm.
S105: 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 reservoir fracture imbibition quality prediction method shown in fig. 1 is suitable for application scenarios in which the fracture opening is smaller than 1 micron or the fracture direction is approximately horizontal, the fracture imbibition height is the fracture imbibition height without considering gravity, the imbibition quality is the imbibition quality without considering gravity, and compared with a scheme considering gravity, a relatively accurate prediction result can be obtained more quickly. As can be seen from the flow shown in fig. 1, the reservoir fracture imbibition quality prediction method (without considering gravity) according to the embodiment of the present invention determines the fracture imbibition height of each fracture at the current 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 an oil and gas resource development scheme of the reservoir, so that the accurate fracture imbibition quality can be predicted quickly, the prediction cost is reduced, and the development process of the oil and gas resource is 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 BDA0002397022590000051
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 BDA0002397022590000052
Figure BDA0002397022590000061
Wherein, the cross section of the core can be determined according to the pre-acquired core diameter and the core height. The cross section of the core is
Figure BDA0002397022590000062
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 BDA0002397022590000063
wherein, R is the imbibition saturation of the rock core (when gravity is not considered) at the current imbibition moment, and the unit is percent; mTThe imbibition mass of the rock core (without considering gravity) at the current imbibition moment 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 fluid flow 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 non-intersecting with 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 BDA0002397022590000064
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 BDA0002397022590000071
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 BDA0002397022590000072
equation (4) can be written as follows:
Figure BDA0002397022590000073
when gravity is not considered, equation (5) can be simplified as:
Figure BDA0002397022590000074
the solution of equation (6) is:
Figure BDA0002397022590000075
the formula (7) is a crack imbibition height expression of a single crack without considering gravity, and the crack imbibition height and
Figure BDA0002397022590000076
is in direct proportion. Wherein a is nl, n is the ratio of the opening degree of the crack to the length, and is dimensionless. Equation (7) can thus be expressed as:
Figure BDA0002397022590000077
for time t, the imbibition mass m of a single fracture without considering gravity can be expressed as:
Figure BDA0002397022590000078
when the gravity is not considered, the imbibition height of a single crack can finally reach the height of the rock core, and the imbibition mass m at the momenteqCan be expressed as:
meq＝ρlaτH。 (9)
wherein m and meqThe 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 BDA0002397022590000081
whereinN (l is not less than zeta) is the number of cracks with length larger 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 BDA0002397022590000082
thus representative Unit AuTotal pore area A ofpCan be calculated to yield:
Figure BDA0002397022590000083
further representative Unit AuCan be calculated as:
Figure BDA0002397022590000084
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 BDA0002397022590000085
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 BDA0002397022590000086
the number of fractures n (l) with a fracture length l can be calculated according to equation (14):
Figure BDA0002397022590000091
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. When gravity is not considered and imbibition stops:
Figure BDA0002397022590000092
when gravity is not considered and the imbibition is not stopped, the imbibition mass of a fracture of length l at time t is:
Figure BDA0002397022590000093
at a certain moment, the fracture in the core consists of two parts, namely, seepage stopping and seepage not stopping, so that the seepage mass of the core without considering the gravity can be expressed as:
Figure BDA0002397022590000094
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 BDA0002397022590000095
the concrete flow of the reservoir fracture imbibition quality prediction method (without considering gravity) 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. And determining the fracture imbibition height of each fracture at the current imbibition moment according to the obtained current imbibition moment, the first physical property parameter and the fracture length of each fracture.
3. A first imbibition quality prediction model and a second imbibition quality prediction model are created.
4. 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.
5. 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.
6. 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.
7. 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 as a function of time for an example of the invention (without regard to gravity). 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.
FIG. 7 is a graph showing the time-dependent change in fracture imbibition height for both the prior art and the present examples (without considering gravity). As shown in fig. 7, the abscissa in fig. 7 is time in units of s; the ordinate is the fracture imbibition height in mm. As shown in fig. 7, the fracture imbibition height obtained by using the capillary imbibition model in the prior art is obviously different from that of the present application, and the error will gradually expand with time. Compared with the prior art, the result obtained by adopting the tortuosity flat plate crack model is more accurate.
In summary, the reservoir fracture imbibition quality prediction method (without considering gravity) of the embodiment of the invention determines the fracture imbibition height of each fracture at the current 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 rapidly 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. 8 is a block diagram of the structure of a reservoir fracture imbibition quality prediction system (without considering gravity) in an embodiment of the invention. As shown in fig. 8, the reservoir fracture imbibition quality prediction system (without considering gravity) includes:
the crack imbibition height unit is used for determining the crack 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;
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 fracture number model creation unit for creating a fracture number model;
an acquisition unit configured to acquire 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.
In one embodiment, the first physical property parameter comprises surface tension, contact angle, wet phase fluid viscosity, and average tortuosity;
the second physical parameter includes: core cross section, fractal dimension, maximum fracture length, minimum fracture length, fracture porosity, and fracture length step length.
In one embodiment, the method further comprises the following steps:
and the cross section determining unit is used for determining the cross section of the core according to the pre-acquired diameter and height of the core.
In summary, the reservoir fracture imbibition quality prediction method (without considering gravity) of the embodiment of the invention determines the fracture imbibition height of each fracture at the current 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 rapidly predicted, the prediction cost is reduced, and the development process of the oil and gas resource 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. 9 is a block diagram of a computer device in an embodiment of the present invention, and referring to fig. 9, the computer device specifically includes the following:
a processor (processor)901 and a memory (memory) 902.
The processor 901 is configured to call a computer program in the memory 902, 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:
determining the fracture imbibition height of each fracture at the current imbibition moment according to the obtained current imbibition moment, the first physical property parameter and the fracture length of each fracture;
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 firstly determines the fracture imbibition height of each fracture at the current imbibition time, then 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 finally 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 so as to create or adjust the oil and gas resource development scheme of the reservoir, so that the accurate fracture imbibition quality can be rapidly 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:
determining the fracture imbibition height of each fracture at the current imbibition moment according to the obtained current imbibition moment, the first physical property parameter and the fracture length of each fracture;
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 invention determines the fracture imbibition height of each fracture at the current 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 rapidly 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 (8)

1.一种储层裂缝渗吸质量预测方法，其特征在于，包括：1. a reservoir fracture imbibition quality prediction method, is characterized in that, comprises: 根据获取的当前渗吸时刻、第一物性参数和各个裂缝的裂缝长度确定各个裂缝在当前渗吸时刻的裂缝渗吸高度；所述第一物性参数包括表面张力、接触角、湿相流体粘度和平均迂曲度，通过如下公式确定各个裂缝在当前渗吸时刻的裂缝渗吸高度：The fracture imbibition height of each fracture at the current imbibition moment is determined according to the obtained current imbibition moment, the first physical property parameter and the fracture length of each fracture; the first physical property parameter includes surface tension, contact angle, wet phase fluid viscosity and The average tortuosity is determined by the following formula to determine the fracture imbibition height of each fracture at the current imbibition moment:
Figure FDA0003201960280000011
Figure FDA0003201960280000011
 其中，Ls为裂缝长度为l的裂缝在当前渗吸时刻的裂缝渗吸高度，n为裂缝的开度与长度之比，l为裂缝长度，σ为所述表面张力，θ为所述接触角，μ为所述湿相流体粘度，τ为所述平均迂曲度，t为渗吸时间，单位为s或min；Among them, L s is the fracture imbibition height of the fracture with the fracture length l at the current imbibition moment, n is the ratio of the opening degree to the length of the fracture, l is the fracture length, σ is the surface tension, and θ is the contact angle, μ is the viscosity of the wet phase fluid, τ is the average tortuosity, t is the imbibition time, in s or min; 创建第一渗吸质量预测模型和第二渗吸质量预测模型；Create a first imbibition quality prediction model and a second imbibition quality prediction model; 所述第一渗吸质量预测模型如下：The first imbibition quality prediction model is as follows: M(l)＝nl2ρLsn(l)；M(l)=nl 2 ρL s n(l); 其中，M(l)为裂缝长度为l的裂缝Ls≤H时的当前渗吸时刻的渗吸质量，单位为kg；ρ为湿相流体密度，n(l)为裂缝长度l的裂缝数量；Among them, M(l) is the imbibition mass at the current imbibition moment when L s ≤ H with a fracture length of l, the unit is kg; ρ is the wet-phase fluid density, and n(l) is the number of fractures with the fracture length l ; 所述第二渗吸质量预测模型如下：The second imbibition quality prediction model is as follows: Meq(l)＝ρnl2τHn(l)；M eq (l)=ρnl 2 τHn(l); 其中，Meq(l)为裂缝长度为l的裂缝Ls＞H时的当前渗吸时刻的渗吸质量，单位为g或kg；H为岩心高度，单位为cm；Among them, M eq (l) is the imbibition mass at the current imbibition moment when the fracture length is l and L s >H, the unit is g or kg; H is the core height, the unit is cm; 当裂缝在当前渗吸时刻的裂缝渗吸高度小于或等于岩心高度时，输入该裂缝的裂缝长度、该裂缝在当前渗吸时刻的裂缝渗吸高度、该裂缝长度的裂缝数量和湿相流体密度至所述第一渗吸质量预测模型中，得到该裂缝在当前渗吸时刻的渗吸质量；When the fracture imbibition height of the fracture at the current imbibition moment is less than or equal to the core height, enter the fracture length of the fracture, the fracture imbibition height of the fracture at the current imbibition moment, the number of fractures at the fracture length and the wet-phase fluid density According to the first imbibition quality prediction model, the imbibition quality of the fracture at the current imbibition moment is obtained; 当裂缝在当前渗吸时刻的裂缝渗吸高度大于岩心高度时，输入该裂缝的裂缝长度、所述岩心高度、该裂缝长度的裂缝数量、所述湿相流体密度和平均迂曲度至所述第二渗吸质量预测模型中，得到该裂缝在当前渗吸时刻的渗吸质量；When the fracture imbibition height of the fracture at the current imbibition moment is greater than the core height, input the fracture length of the fracture, the core height, the number of fractures in the fracture length, the wet phase fluid density and the average tortuosity to the first In the second imbibition quality prediction model, the imbibition quality of the fracture at the current imbibition moment is obtained; 根据各个裂缝在当前渗吸时刻的渗吸质量预测岩心在当前渗吸时刻的渗吸质量以创建或调整储层的油气资源开发方案。According to the imbibition quality of each fracture at the current imbibition moment, the imbibition quality of the core at the current imbibition moment is predicted to create or adjust the oil and gas resource development plan of the reservoir. 2.根据权利要求1所述的储层裂缝渗吸质量预测方法，其特征在于，还包括：2. The method for predicting the imbibition quality of reservoir fractures according to claim 1, further comprising: 创建裂缝数量模型；Create a model of the number of cracks; 获取第二物性参数；Get the second physical parameter; 输入各个裂缝长度和所述第二物性参数至所述裂缝数量模型中，得到各个裂缝长度的裂缝数量；inputting each fracture length and the second physical property parameter into the fracture quantity model to obtain the fracture quantity of each fracture length; 所述第二物性参数包括岩心横截面、分形维数、最大裂缝长度、最小裂缝长度、裂缝孔隙度和裂缝长度步长，所述裂缝数量模型如下：The second physical property parameters include core cross section, fractal dimension, maximum fracture length, minimum fracture length, fracture porosity and fracture length step, and the fracture number model is as follows:
Figure FDA0003201960280000021
Figure FDA0003201960280000021
 其中，n(l)为裂缝长度l的裂缝数量，l为裂缝长度，Af为所述岩心横截面，n为裂缝的开度与长度之比，Df为所述分形维数，lmax为所述最大裂缝长度，lmin为所述最小裂缝长度，φf为所述裂缝孔隙度，Δl为所述裂缝长度步长，单位为μm。Among them, n(l) is the number of fractures with the fracture length l, l is the length of the fracture, A f is the cross section of the core, n is the ratio of the opening degree to the length of the fracture, D f is the fractal dimension, and l max is the maximum fracture length, l min is the minimum fracture length, φ f is the fracture porosity, and Δl is the fracture length step, in μm. 3.根据权利要求2所述的储层裂缝渗吸质量预测方法，其特征在于，还包括：3. The method for predicting the imbibition quality of reservoir fractures according to claim 2, further comprising: 根据预先获取的岩心直径确定岩心横截面。The core cross section is determined according to the pre-obtained core diameter. 4.一种储层裂缝渗吸质量预测系统，其特征在于，包括：4. A reservoir fracture imbibition quality prediction system, characterized in that, comprising: 裂缝渗吸高度单元，用于根据获取的当前渗吸时刻、第一物性参数和各个裂缝的裂缝长度确定各个裂缝在当前渗吸时刻的裂缝渗吸高度；所述第一物性参数包括表面张力、接触角、湿相流体粘度和平均迂曲度，所述裂缝渗吸高度单元具体用于通过如下公式确定各个裂缝在当前渗吸时刻的裂缝渗吸高度：The fracture imbibition height unit is used to determine the fracture imbibition height of each fracture at the current imbibition moment according to the obtained current imbibition moment, the first physical property parameter and the fracture length of each fracture; the first physical property parameter includes surface tension, Contact angle, wet phase fluid viscosity and average tortuosity, the fracture imbibition height unit is specifically used to determine the fracture imbibition height of each fracture at the current imbibition moment by the following formula:
Figure FDA0003201960280000022
Figure FDA0003201960280000022
 其中，Ls为裂缝长度为l的裂缝在当前渗吸时刻的裂缝渗吸高度，n为裂缝的开度与长度之比，l为裂缝长度，σ为所述表面张力，θ为所述接触角，μ为所述湿相流体粘度，τ为所述平均迂曲度，t为渗吸时间，单位为s或min；Among them, L s is the fracture imbibition height of the fracture with the fracture length l at the current imbibition moment, n is the ratio of the opening degree to the length of the fracture, l is the fracture length, σ is the surface tension, and θ is the contact angle, μ is the viscosity of the wet phase fluid, τ is the average tortuosity, t is the imbibition time, in s or min; 渗吸质量预测模型创建单元，用于创建第一渗吸质量预测模型和第二渗吸质量预测模型；The imbibition quality prediction model creation unit is used to create the first imbibition quality prediction model and the second imbibition quality prediction model; 裂缝渗吸质量单元，用于当裂缝在当前渗吸时刻的裂缝渗吸高度小于或等于岩心高度时，输入该裂缝的裂缝长度、该裂缝在当前渗吸时刻的裂缝渗吸高度、该裂缝长度的裂缝数量和湿相流体密度至所述第一渗吸质量预测模型中，得到该裂缝在当前渗吸时刻的渗吸质量；当裂缝在当前渗吸时刻的裂缝渗吸高度大于岩心高度时，输入该裂缝的裂缝长度、所述岩心高度、该裂缝长度的裂缝数量、所述湿相流体密度和平均迂曲度至所述第二渗吸质量预测模型中，得到该裂缝在当前渗吸时刻的渗吸质量；Fracture imbibition quality unit, used to input the fracture length of the fracture, the fracture imbibition height of the fracture at the current imbibition moment, and the fracture length when the fracture imbibition height of the fracture at the current imbibition moment is less than or equal to the core height The number of fractures and the density of wet phase fluid are added to the first imbibition quality prediction model, and the imbibition quality of the fracture at the current imbibition moment is obtained; when the fracture imbibition height of the fracture at the current imbibition moment is greater than the core height, Input the fracture length of the fracture, the core height, the number of fractures in the fracture length, the wet-phase fluid density and the average tortuosity into the second imbibition quality prediction model, and obtain the current imbibition moment of the fracture. imbibition quality; 所述第一渗吸质量预测模型如下：The first imbibition quality prediction model is as follows: M(l)＝nl2ρLsn(l)；M(l)=nl 2 ρL s n(l); 其中，M(l)为裂缝长度为l的裂缝Ls≤H时的当前渗吸时刻的渗吸质量，单位为kg；ρ为湿相流体密度，n(l)为裂缝长度l的裂缝数量；Among them, M(l) is the imbibition mass at the current imbibition moment when L s ≤ H with a fracture length of l, the unit is kg; ρ is the wet-phase fluid density, and n(l) is the number of fractures with the fracture length l ; 所述第二渗吸质量预测模型如下：The second imbibition quality prediction model is as follows: Meq(l)＝ρnl2τHn(l)；M eq (l)=ρnl 2 τHn(l); 其中，Meq(l)为裂缝长度为l的裂缝Ls＞H时的当前渗吸时刻的渗吸质量，单位为g或kg；H为岩心高度，单位为cm；Among them, M eq (l) is the imbibition mass at the current imbibition moment when the fracture length is l and L s >H, the unit is g or kg; H is the core height, the unit is cm; 预测单元，用于根据各个裂缝在当前渗吸时刻的渗吸质量预测岩心在当前渗吸时刻的渗吸质量以创建或调整储层的油气资源开发方案。The prediction unit is used to predict the imbibition quality of the core at the current imbibition moment according to the imbibition quality of each fracture at the current imbibition moment, so as to create or adjust the oil and gas resource development plan of the reservoir. 5.根据权利要求4所述的储层裂缝渗吸质量预测系统，其特征在于，还包括：5. The reservoir fracture imbibition quality prediction system according to claim 4, characterized in that, further comprising: 裂缝数量模型创建单元，用于创建裂缝数量模型；The number of cracks model creation unit is used to create the number of cracks model; 获取单元，用于获取第二物性参数；an acquisition unit for acquiring the second physical property parameter; 裂缝数量单元，用于输入各个裂缝长度和所述第二物性参数至所述裂缝数量模型中，得到各个裂缝长度的裂缝数量；a fracture number unit, used for inputting each fracture length and the second physical property parameter into the fracture number model to obtain the fracture number of each fracture length; 所述第二物性参数包括岩心横截面、分形维数、最大裂缝长度、最小裂缝长度、裂缝孔隙度和裂缝长度步长，所述裂缝数量模型如下：The second physical property parameters include core cross section, fractal dimension, maximum fracture length, minimum fracture length, fracture porosity and fracture length step, and the fracture number model is as follows:
Figure FDA0003201960280000031
Figure FDA0003201960280000031
 其中，n(l)为裂缝长度l的裂缝数量，l为裂缝长度，Af为所述岩心横截面，n为裂缝的开度与长度之比，Df为所述分形维数，lmax为所述最大裂缝长度，lmin为所述最小裂缝长度，φf为所述裂缝孔隙度，Δl为所述裂缝长度步长，单位为μm。Among them, n(l) is the number of fractures with the fracture length l, l is the length of the fracture, A f is the cross section of the core, n is the ratio of the opening degree to the length of the fracture, D f is the fractal dimension, and l max is the maximum fracture length, l min is the minimum fracture length, φ f is the fracture porosity, and Δl is the fracture length step, in μm. 6.根据权利要求5所述的储层裂缝渗吸质量预测系统，其特征在于，还包括：6. The reservoir fracture imbibition quality prediction system according to claim 5, characterized in that, further comprising: 横截面确定单元，用于根据预先获取的岩心直径确定岩心横截面。The cross section determination unit is used to determine the core cross section according to the pre-acquired core diameter. 7.一种计算机设备，包括存储器、处理器及存储在存储器上并在处理器上运行的计算机程序，其特征在于，所述处理器执行所述计算机程序时实现权利要求1至3任一项所述的储层裂缝渗吸质量预测方法的步骤。7. A computer device comprising a memory, a processor and a computer program stored on the memory and running on the processor, wherein the processor implements any one of claims 1 to 3 when the processor executes the computer program The steps of the method for predicting imbibition quality of reservoir fractures. 8.一种计算机可读存储介质，其上存储有计算机程序，其特征在于，所述计算机程序被处理器执行时实现权利要求1至3任一项所述的储层裂缝渗吸质量预测方法的步骤。8. A computer-readable storage medium on which a computer program is stored, characterized in that, when the computer program is executed by a processor, the method for predicting the imbibition quality of a reservoir fracture according to any one of claims 1 to 3 is realized A step of.
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