CN117684934A - Shale oil reservoir carbon dioxide huff and puff effect prediction method and device - Google Patents
Shale oil reservoir carbon dioxide huff and puff effect prediction method and device Download PDFInfo
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- 229910002092 carbon dioxide Inorganic materials 0.000 title claims abstract description 119
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- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 41
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Abstract
The invention discloses a method and a device for predicting carbon dioxide huff and puff effect of a shale oil reservoir. Wherein the method comprises the following steps: obtaining the oil increasing amount of a unit fracture area of a shale oil reservoir, wherein the oil increasing amount of the unit fracture area is dynamically changed along with the diffusion depth of carbon dioxide gas in a fracture of the shale oil reservoir, and the carbon dioxide gas is pre-injected into the shale oil reservoir; determining a target fracture area of the shale oil reservoir, wherein the target fracture area dynamically changes along with the accumulated open time of the shale oil reservoir; and determining an oil-increasing amount evaluation result of the shale oil reservoir based on the target fracture area and the oil-increasing amount per unit fracture area. The method solves the technical problems of large calculated amount, long time consumption, large crack characterization difficulty and inaccurate evaluation because the carbon dioxide huff-puff effect of the shale oil reservoir in the related technology is mainly determined by a conventional oil reservoir numerical simulation method.
Description
Technical Field
The invention relates to the technical field of shale oil reservoir development, in particular to a method and a device for predicting carbon dioxide huff and puff effects of a shale oil reservoir.
Background
Shale oil is widely used as an unconventional oil and gas resource, and due to low permeability of a reservoir, water injection is difficult to establish an effective displacement pressure system under an economic limit well pattern, and the development of shale oil benefits is generally realized by adopting a horizontal well and volume fracturing mode at present. Molecular diffusion is an important mechanism for shale oil to improve recovery efficiency in the carbon dioxide huff and puff process. How to consider molecular diffusion to carry out optimal design to shale oil carbon dioxide throughput gas injection becomes a key ring influencing shale oil gas injection throughput effect and benefit, wherein the design throughput gas injection is too small, the throughput oil increasing effect is poor, the design gas injection is too large, invalid circulation of gas injection is caused, and throughput benefit is influenced.
In the prior art, the shale oil throughput parameter optimization design is characterized in that oil increment is predicted by using oil reservoir numerical simulation software through geologic modeling and oil reservoir numerical simulation according to a conventional oil reservoir method, and the oil increment is mainly predicted by adjusting oil gas permeation in the gas injection process, so that the realization mode is single. Meanwhile, because the difficulty of establishing a fracture model by using the oil reservoir numerical simulation effect is high, the accuracy of representing the fracture by the fracture model under the unconventional oil reservoir volume fracturing scale is poor, and meanwhile, the defects of more needed basic data, long time consumption, more influence factors and the like are overcome.
In view of the above problems, no effective solution has been proposed at present.
Disclosure of Invention
The embodiment of the invention provides a method and a device for predicting the carbon dioxide huff-puff effect of a shale oil reservoir, which at least solve the technical problems of large calculated amount, long time consumption, large difficulty in crack characterization and inaccurate evaluation because the carbon dioxide huff-puff effect of the shale oil reservoir in the related technology is mainly determined by a conventional oil reservoir numerical simulation method.
According to an aspect of the embodiment of the invention, there is provided a shale oil reservoir carbon dioxide huff-puff effect prediction method, comprising: obtaining the oil increasing amount of a unit fracture area of a shale oil reservoir, wherein the oil increasing amount of the unit fracture area is dynamically changed along with the diffusion depth of carbon dioxide gas in a fracture of the shale oil reservoir, and the carbon dioxide gas is pre-injected into the shale oil reservoir; determining a target fracture area of the shale oil reservoir, wherein the target fracture area dynamically changes along with the accumulated open time of the shale oil reservoir; determining an oil-up evaluation result of the shale oil reservoir based on the target fracture area and the oil-up per unit fracture area; and determining the carbon dioxide huff-puff effect of the shale oil reservoir according to the oil increment evaluation result.
Optionally, determining the target fracture area of the shale oil reservoir includes: obtaining production history data of the shale oil reservoir, wherein the production history data at least comprises: crude oil yield, water content, formation pressure and bottom hole flowing pressure corresponding to the shale oil reservoir; the target fracture area is determined based on the production history data.
Optionally, the determining the target fracture area based on the production history data includes: calculating a plurality of crack areas at different historical moments based on the production historical data; selecting a crack area corresponding to the water content within a first preset range from the plurality of crack areas; and determining an average value of the crack areas corresponding to the water content in a first preset range, and taking the average value as the target crack area.
Optionally, the obtaining a plurality of crack areas at different historical moments based on the production history data includes: acquiring reservoir physical parameters, crude oil high-pressure physical parameters and accumulated well opening time corresponding to the shale oil reservoir, wherein the reservoir physical parameters at least comprise: crude oil saturation pressure, crude oil compression coefficient, formation volume coefficient and formation crude oil viscosity, wherein the reservoir physical parameters at least comprise: matrix-over-pressure permeability, matrix-over-pressure porosity, irreducible water saturation; based on the production history data, the reservoir physical property parameters, the crude oil high-pressure physical property parameters and the accumulated well opening time, a plurality of crack areas at different historical moments are obtained in the following mode: Wherein A is f1 Represents crack area, q at different historic moments o Representing the above crude oil yield, B o Representing the formation volume coefficient, P i Representing the formation pressure, P wf Represents the bottom hole flow pressure, mu o Representing the viscosity of the crude oil in the stratum, t k Represents the cumulative open time, K represents the matrix overburden permeability, phi represents the matrix overburden porosity, C t Representing an integrated compression factor, wherein the integrated compression factor is determined based on the crude oil compression factor and the irreducible water saturation.
Optionally, the determining the oil-up estimation result of the shale oil reservoir based on the target fracture area and the oil-up per unit fracture area includes: acquiring the surface crude oil density corresponding to the shale oil deposit and the target diffusion distance of the carbon dioxide gas in the cracks of the shale oil deposit, wherein the target diffusion distance is the distance between the position, in which the concentration of the carbon dioxide gas in the cracks of the shale oil deposit reaches a preset concentration, of the carbon dioxide gas and the crack surface of the shale oil deposit after the carbon dioxide gas is injected into the shale oil deposit and the shale oil deposit is subjected to well soaking treatment; determining an oil-up evaluation result of the shale oil reservoir based on the ground crude oil density, the target diffusion distance, the target fracture area and the oil-up per unit fracture area; and determining the carbon dioxide huff-puff effect of the shale oil reservoir according to the oil increment evaluation result.
Optionally, determining the oil-up evaluation result of the shale oil reservoir based on the ground crude oil density, the target diffusion distance, the target fracture area and the oil-up per unit fracture area:wherein A is f For the target fracture area ρ o For the above ground crude oil density, d is the above target diffusion distance, q o (x) And (3) increasing the oil quantity for the unit crack area.
Optionally, the method further comprises: obtaining the surface crude oil density, the diffusion depth, the matrix-based pressure porosity, the matrix-based water saturation, the crude oil volume coefficient and the crude oil volume expansion factor corresponding to the shale oil deposit, wherein the crude oil volume expansion factor is the expansion factor of the crude oil volume in the shale oil deposit compared with the expansion factor of the crude oil before the carbon dioxide gas is not injected after the carbon dioxide gas is injected into the shale oil deposit and the shale oil deposit is subjected to well soaking treatment, and the crude oil volume expansion factor is dynamically changed along with the diffusion depth of the carbon dioxide gas in cracks of the shale oil deposit; determining the oil increase per unit fracture area based on the surface crude oil density, the diffusion depth, the matrix-over-pressure porosity, the matrix-tie-water saturation, the crude oil volume coefficient, and the crude oil volume expansion multiple.
Optionally, determining the oil increase per unit fracture area based on the surface crude oil density, the diffusion depth, the matrix-over-pressure porosity, the matrix-tie-water saturation, the crude oil volume factor, and the crude oil volume expansion factor:wherein q o (x) Indicating the oil increase per unit crack area ρ o Represents the above-mentioned surface crude oil density, x represents the above-mentioned diffusion depth, phi represents the above-mentioned matrix-coated porosity, S wi Representing the matrix irreducible water saturation, B o Representing the volume coefficient of the crude oil, V s (x) The volume expansion ratio of the crude oil is shown.
According to another aspect of the embodiment of the present invention, there is also provided a shale oil reservoir carbon dioxide huff-puff effect prediction apparatus, including: the device comprises an acquisition module, a control module and a control module, wherein the acquisition module is used for acquiring the oil increasing amount of a unit fracture area of a shale oil reservoir, the oil increasing amount of the unit fracture area is dynamically changed along with the diffusion depth of carbon dioxide gas in a fracture of the shale oil reservoir, and the carbon dioxide gas is pre-injected into the shale oil reservoir; the first determining module is used for determining a target fracture area of the shale oil deposit, wherein the target fracture area dynamically changes along with the accumulated open time of the shale oil deposit; the second determining module is used for determining an oil increasing amount evaluation result of the shale oil reservoir based on the target fracture area and the oil increasing amount per unit fracture area; and determining the carbon dioxide huff-puff effect of the shale oil reservoir according to the oil increment evaluation result.
According to another aspect of the embodiment of the present invention, there is further provided a non-volatile storage medium, where a plurality of instructions are stored, where the instructions are adapted to be loaded and executed by a processor to any one of the shale oil reservoir carbon dioxide throughput effect prediction methods described above.
In the embodiment of the invention, the oil increasing amount of the unit fracture area of the shale oil deposit is obtained, wherein the oil increasing amount of the unit fracture area is dynamically changed along with the diffusion depth of carbon dioxide gas in the fracture of the shale oil deposit, and the carbon dioxide gas is injected into the shale oil deposit in advance; determining a target fracture area of the shale oil reservoir, wherein the target fracture area dynamically changes along with the accumulated open time of the shale oil reservoir; determining an oil-up evaluation result of the shale oil reservoir based on the target fracture area and the oil-up per unit fracture area; according to the oil increment evaluation result, the carbon dioxide huff-puff effect of the shale oil reservoir is determined, and the purpose of determining the carbon dioxide huff-puff effect of the shale oil reservoir by comprehensively considering the factors of gas diffusion and crack area dynamic change is achieved, so that the technical effects of improving the prediction efficiency and the prediction accuracy of the carbon dioxide huff-puff effect of the shale oil reservoir are achieved, and the technical problems that the carbon dioxide huff-puff effect of the shale oil reservoir in the related art is determined mainly by means of a conventional oil reservoir numerical simulation method, and the problems of large calculated amount, long time consumption, high difficulty in crack characterization and inaccurate evaluation are solved.
Drawings
The accompanying drawings, which are included to provide a further understanding of the invention and are incorporated in and constitute a part of this application, illustrate embodiments of the invention and together with the description serve to explain the invention and do not constitute a limitation on the invention. In the drawings:
FIG. 1 is a flow chart of a shale reservoir carbon dioxide huff-puff effect prediction method according to an embodiment of the present invention;
FIG. 2a is a schematic diagram showing the correspondence between diffusion depth and carbon dioxide gas concentration at different optional soak times according to an embodiment of the present invention;
FIG. 2b is a schematic diagram of an alternative target diffusion distance versus kill time according to an embodiment of the present invention;
FIG. 3 is a schematic diagram of an alternative crude oil volume expansion ratio versus gas concentration of carbon dioxide gas in accordance with an embodiment of the present invention;
FIG. 4 is a schematic structural diagram of a shale reservoir carbon dioxide huff-puff effect prediction device according to an embodiment of the present invention;
fig. 5 is a schematic structural view of an electronic device according to an embodiment of the present invention.
Detailed Description
In order that those skilled in the art will better understand the present invention, a technical solution in the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings in which it is apparent that the described embodiments are only some embodiments of the present invention, not all embodiments. All other embodiments, which can be made by those skilled in the art based on the embodiments of the present invention without making any inventive effort, shall fall within the scope of the present invention.
It should be noted that the terms "first," "second," and the like in the description and the claims of the present invention and the above figures are used for distinguishing between similar objects and not necessarily for describing a particular sequential or chronological order. It is to be understood that the data so used may be interchanged where appropriate such that the embodiments of the invention described herein may be implemented in sequences other than those illustrated or otherwise described herein. Furthermore, the terms "comprises," "comprising," and "having," and any variations thereof, are intended to cover a non-exclusive inclusion, such that a process, method, system, article, or apparatus that comprises a list of steps or elements is not necessarily limited to those steps or elements expressly listed but may include other steps or elements not expressly listed or inherent to such process, method, article, or apparatus.
In accordance with an embodiment of the present invention, a method embodiment of shale reservoir carbon dioxide throughput effect prediction is provided, it being noted that the steps illustrated in the flow chart of the figures may be performed in a computer system, such as a set of computer executable instructions, and, although a logical sequence is illustrated in the flow chart, in some cases, the steps illustrated or described may be performed in a different order than that illustrated herein.
FIG. 1 is a flow chart of a shale reservoir carbon dioxide huff-puff effect prediction method according to an embodiment of the present invention, as shown in FIG. 1, the method comprising the steps of:
step S102, obtaining the oil increment amount of a unit fracture area of a shale oil reservoir;
step S104, determining the target fracture area of the shale oil reservoir;
step S106, determining an oil-increasing evaluation result of the shale oil reservoir based on the target fracture area and the oil-increasing amount per unit fracture area; and determining the carbon dioxide huff-puff effect of the shale oil reservoir according to the oil increment evaluation result.
Through the steps, the purpose of determining the carbon dioxide huff-puff effect of the shale oil reservoir by comprehensively considering the factors of gas diffusion and dynamic change of the fracture area can be achieved, so that the technical effects of improving the prediction efficiency and the prediction accuracy of the carbon dioxide huff-puff effect of the shale oil reservoir are achieved, and the technical problems that the carbon dioxide huff-puff effect of the shale oil reservoir in the related technology is determined mainly by means of a conventional oil reservoir numerical simulation method, and the problems of large calculated amount, long time consumption, high fracture characterization difficulty and inaccurate assessment exist are solved.
Optionally, the oil increasing amount per unit fracture area is dynamically changed along with the diffusion depth of carbon dioxide gas in the fracture of the shale oil reservoir, and the carbon dioxide gas is pre-injected into the shale oil reservoir; the target fracture area dynamically changes with the accumulated open time of the shale oil reservoir.
In the related technology, the gas injection quantity is optimally designed by using the oil reservoir numerical simulation software through geologic modeling and oil reservoir numerical simulation, and the prediction of the throughput effect is realized by mainly adjusting the oil gas permeation in the gas injection process, so that the contribution of the molecular diffusion action mechanism of the unconventional oil reservoir caused by the pore scale effect to the improvement of the recovery ratio is not considered. Meanwhile, the accuracy of the oil reservoir numerical simulation prediction method mainly depends on the accuracy of a fracture model, but the characterization difficulty of the fracture is high and the accuracy is poor under the unconventional oil reservoir volume fracturing scale. According to the method for predicting the carbon dioxide huff and puff effect of the shale oil deposit, when the carbon dioxide huff and puff effect of the shale oil deposit is determined on the basis of the oil increase of the shale oil deposit, the factors of gas diffusion and dynamic change of the fracture area are considered, namely, the oil increase of the unit fracture area is determined according to the gas diffusion principle, the dynamic fracture area is obtained according to the accumulated well opening time of the shale oil deposit, the obtained oil increase of the shale oil deposit on the basis has higher accuracy and is closer to reality, and further the obtained carbon dioxide huff and puff effect of the shale oil deposit is predicted more accurately.
In an alternative embodiment, the determining the target fracture area of the shale reservoir includes:
Obtaining production history data of the shale oil reservoir, wherein the production history data at least comprises: crude oil yield, water content, formation pressure and bottom hole flowing pressure corresponding to the shale oil reservoir;
the target fracture area is determined based on the production history data.
Optionally, when determining the target fracture area, the factors such as the crude oil yield, the water content, the formation pressure, the bottom hole flow pressure and the like corresponding to the shale oil reservoir and the dynamic change conditions of the factors along with time are considered at the same time, so that the obtained fracture area (namely the target fracture area) of the shale oil reservoir is more fit with reality, the requirement of the shale oil reservoir gas injection amount calculation is better met, the obtained shale oil reservoir gas injection amount is higher in accuracy, and the obtained shale oil reservoir carbon dioxide throughput effect is better predicted.
In an alternative embodiment, the determining the target fracture area based on the production history data includes:
calculating a plurality of crack areas at different historical moments based on the production historical data;
selecting a crack area corresponding to the water content within a first preset range from the plurality of crack areas;
And determining an average value of the crack areas corresponding to the water content in a first preset range, and taking the average value as the target crack area.
Optionally, according to the production history data of the shale oil reservoir, collecting the crude oil yield, the water content, the formation pressure and the bottom hole flowing pressure at different historic moments, and the reservoir physical parameters, the crude oil high-pressure physical parameters and the accumulated well opening time corresponding to the shale oil reservoir. Determining a plurality of crack areas at different historical moments based on the crude oil yield, the water content, the formation pressure, the bottom hole flowing pressure, reservoir physical parameters corresponding to the shale oil reservoir, crude oil high-pressure physical parameters and accumulated well opening time; and calculating an average value of the plurality of crack areas meeting the water content requirement as the target crack area when the water content is in a first preset range (for example, 15%) and the plurality of crack areas are corresponding to the first preset range (for example, less than 15%).
Optionally, the water content is determined according to a water content change curve acquired in situ from the shale oil reservoir. For example, the first preset range of the change of the water content is selected according to the change curve of the water content to be less than 15% of the water content. In addition, since the flow fracture area (i.e., the target fracture area) changes with time, it is mainly affected by the production pressure difference, the shale reservoir yield, the reservoir physical properties, the fluid physical properties, and the like, and when the flow fracture area is taken, it is recommended to select a calculated value when the water content is reduced to 15% or less after completion of flowback of the fracturing fluid.
In an alternative embodiment, the obtaining a plurality of crack areas at different historical moments based on the production history data includes:
acquiring reservoir physical parameters, crude oil high-pressure physical parameters and accumulated well opening time corresponding to the shale oil reservoir, wherein the reservoir physical parameters at least comprise: crude oil saturation pressure, crude oil compression coefficient, formation volume coefficient and formation crude oil viscosity, wherein the reservoir physical parameters at least comprise: matrix-over-pressure permeability, matrix-over-pressure porosity, irreducible water saturation;
based on the production history data, the reservoir physical property parameters, the crude oil high-pressure physical property parameters and the accumulated well opening time, a plurality of crack areas at different historical moments are obtained in the following mode:
wherein A is f1 Represents the crack area at different historical moments, the unit is m 2 ；q o Representing the above crude oil yield in m 3 /d (cubic meters/minute); b (B) o Representing the stratum volume coefficient in the form of decimal; p (P) i The formation pressure is expressed in MPa (megapascals); p (P) wf Representing the bottom hole flow pressure in MPa; mu (mu) o Representing the viscosity of the crude oil in the stratum, wherein the unit is Cp (centipoise); t is t k The accumulated open time is expressed in d (minutes); k represents the above matrix overpressure permeability in mD (millidarcy); phi represents the covering porosity of the matrix, and the unit is; c (C) t Represents the integrated compression coefficient in mD (millidarcy); wherein said integrated compressibility is determined based on said crude oil compressibility and said irreducible water saturation, and said crude oil yield may be daily crude oil yield.
Alternatively, the above-mentioned integrated compression coefficient C is obtained by t ：
Wherein C is o The compression coefficient of crude oil is expressed, and the unit is 1/MPa; c (C) w The compression coefficient of formation water is expressed, and the unit is 1/MPa; c (C) f The compression coefficient of a rock pore system is expressed, and the unit is 1/MPa; s is S wi Representing matrix irreducible water saturation, may be in decimal form.
Optionally, the actual exploitation process of the shale oil reservoir needs to monitor various parameters in real time, andand generating a corresponding test report. Most of the parameter distances involved in the embodiments of the present invention can be obtained from the generated test report. For example, the above-mentioned crude oil high-pressure physical properties, such as crude oil saturation pressure (p) b ) Volume coefficient (B) o ) Compression factor of crude oil (C) o ) Viscosity (mu) o ) Isoparametric, wherein the volume coefficient and the compression coefficient are affected by formation pressure; the reservoir physical parameters described above, such as, for example, the overburden porosity (phi) and permeability (K), the irreducible water saturation (S) under reservoir matrix reservoir conditions, may be obtained, but are not limited to, by pre-collected in-shale reservoir core test analysis reports wc )。
Optionally, collecting shale reservoir pressure measurement data before shale reservoir production to obtain shale reservoir original stratum pressure (p i )。
Alternatively, the shale reservoir may be tested for its corresponding rock pore compression factor according to, but not limited to, the rock pore volume compression factor determination method standard. The compression coefficient test is carried out on the shale oil core according to the SY/T5815-2016 rock pore volume compression coefficient determination method of petroleum carbon dioxide industry standard to obtain the rock pore compression coefficient (C) f )。
In an alternative embodiment, the determining the oil-up estimation result of the shale oil reservoir based on the target fracture area and the oil-up per unit fracture area includes:
acquiring the surface crude oil density corresponding to the shale oil reservoir and the target diffusion distance of the carbon dioxide gas in cracks of the shale oil reservoir;
and determining an oil-up evaluation result of the shale oil reservoir based on the ground crude oil density, the target diffusion distance, the target fracture area and the oil-up per unit fracture area.
Optionally, the target diffusion distance is a distance between a position where the carbon dioxide concentration of the carbon dioxide gas in the fracture of the shale oil reservoir reaches a preset concentration and a fracture surface of the shale oil reservoir after the carbon dioxide gas is injected into the shale oil reservoir and the shale oil reservoir is subjected to a well soaking treatment. That is, the target diffusion distance may be understood as the furthest distance that the carbon dioxide gas diffuses in the cracks of the shale reservoir. The predetermined concentration may be, but is not limited to, 10% -5%.
It should be noted that, the above carbon dioxide gas concentration relates to the soak time t and the diffusion depth (i.e., the distance from the fracture surface), and different soak times and/or diffusion depths correspond to different gas concentrations, and fig. 2a shows the correspondence between diffusion depths and carbon dioxide gas concentrations at different soak times. It can be seen that different target diffusion distances can be obtained according to different well-soaking times, and the point that the concentration of the carbon dioxide gas reaches the preset concentration in fig. 2a is extracted, so that the relationship between the target diffusion distance and the well-soaking time is shown in fig. 2 b.
Optionally, determining the oil-up estimation result of the shale oil reservoir based on the above ground crude oil density, the above target diffusion distance, the above target fracture area, and the above oil-up per unit fracture area by:
wherein A is f The unit of the target crack area is m 2 ；ρ o The density of the ground crude oil is expressed in g/cm < 3 >; (g/cc); d is the target diffusion distance in m (meters); q o (x) The unit of the oil increase amount per unit crack area is t (ton). In an alternative embodiment, the method further comprises:
acquiring the surface crude oil density, the diffusion depth, the matrix overburden porosity, the matrix-bound water saturation, the crude oil volume coefficient and the crude oil volume expansion multiple corresponding to the shale oil reservoir;
Determining the oil increase per unit fracture area based on the surface crude oil density, the diffusion depth, the matrix-over-pressure porosity, the matrix-tie-water saturation, the crude oil volume coefficient, and the crude oil volume expansion multiple.
Optionally, the volume expansion factor of the crude oil is an expansion factor of the crude oil in the shale oil reservoir before the carbon dioxide gas is not injected after the carbon dioxide gas is injected into the shale oil reservoir and the shale oil reservoir is subjected to the well soaking treatment, and the volume expansion factor of the crude oil is dynamically changed along with the diffusion depth of the carbon dioxide gas in cracks of the shale oil reservoir.
Optionally, determining the oil enhancement per unit fracture area based on the surface crude oil density, the diffusion depth, the matrix-over-pressure porosity, the matrix-tie-water saturation, the crude oil volume factor, and the crude oil volume expansion factor by:
wherein q o (x) The unit of the oil increment per unit crack area is t (ton); ρ o Representing the density of the above ground crude oil in g/cm 3 The method comprises the steps of carrying out a first treatment on the surface of the (g/cc); x represents the diffusion depth in m (meters); phi represents the covering porosity of the matrix, and the unit is; s is S wi Representing the matrix irreducible water saturation in decimal form; b (B) o Representing the volume coefficient of the crude oil in a decimal form; v (V) s (x) The volume expansion ratio of the crude oil is expressed in decimal form.
In an alternative embodiment, the method further comprises:
acquiring historical monitoring data in a preset period, wherein the historical monitoring data at least comprises: a first history data determined based on the expansion ratio of the crude oil volume and the gas concentration of the carbon dioxide gas, and a second history data determined based on the diffusion depth and the gas concentration of the carbon dioxide gas;
determining a first regression equation of relation between the volume expansion coefficient of the crude oil and the gas concentration of the carbon dioxide gas based on the first history data;
determining a second regression equation of relation between the diffusion depth and the gas concentration of the carbon dioxide gas based on the second history data;
and determining and obtaining the volume expansion multiple of the crude oil changing along with the diffusion depth based on the first regression relation equation and the second regression relation equation.
Optionally, the volume expansion coefficient of the crude oil in the shale oil reservoir is related to the gas concentration of the carbon dioxide gas (such as the carbon dioxide gas), the relationship between the volume expansion coefficient of the crude oil in the shale oil reservoir and the gas concentration of the carbon dioxide gas is shown in fig. 3, in addition, the diffusion depth of the carbon dioxide gas and the gas concentration of the carbon dioxide gas have a certain relationship, a first relationship diagram between the volume expansion coefficient of the crude oil and the gas concentration of the carbon dioxide gas is drawn based on historical monitoring data, and the first relationship diagram is fitted to obtain a first regression relationship equation between the volume expansion coefficient of the crude oil and the gas concentration of the carbon dioxide gas; drawing a second relation graph between the diffusion depth of the carbon dioxide gas and the gas concentration of the carbon dioxide gas based on the historical monitoring data, and fitting the second relation graph to obtain a second regression relation equation between the diffusion depth of the carbon dioxide gas and the gas concentration of the carbon dioxide gas; and carrying out simultaneous solving on the first regression relation equation and the second regression relation equation to obtain a relation equation between the diffusion depth of the carbon dioxide gas and the volume expansion multiple of the crude oil, and obtaining the volume expansion multiple of the crude oil changing along with the diffusion depth based on the relation equation.
In this embodiment, a device for predicting the carbon dioxide huff and puff effect of a shale oil reservoir is further provided, and the device is used for implementing the foregoing embodiments and preferred embodiments, and is not described again. As used below, the terms "module," "apparatus" may be a combination of software and/or hardware that implements a predetermined function. While the means described in the following embodiments are preferably implemented in software, implementation in hardware, or a combination of software and hardware, is also possible and contemplated.
According to an embodiment of the present invention, there is further provided an apparatus embodiment for implementing the method for predicting a carbon dioxide huff-and-puff effect of a shale oil reservoir, and fig. 4 is a schematic structural diagram of an apparatus for predicting a carbon dioxide huff-and-puff effect of a shale oil reservoir according to an embodiment of the present invention, as shown in fig. 4, where the apparatus for predicting a carbon dioxide huff-and-puff effect of a shale oil reservoir includes: an acquisition module 400, a first determination module 402, a second determination module 404, wherein:
the obtaining module 400 is configured to obtain an increase in oil per unit fracture area of a shale oil reservoir, where the increase in oil per unit fracture area dynamically changes with a diffusion depth of carbon dioxide gas in a fracture of the shale oil reservoir, and the carbon dioxide gas is pre-injected into the shale oil reservoir;
The first determining module 402 is connected to the obtaining module 400, and is configured to determine a target fracture area of the shale oil reservoir, where the target fracture area dynamically changes along with an accumulated open time of the shale oil reservoir;
the second determining module 404, coupled to the first determining module 402, is configured to determine an oil-up estimation result of the shale reservoir based on the target fracture area and the oil-up per unit fracture area; and determining the carbon dioxide huff-puff effect of the shale oil reservoir according to the oil increment evaluation result.
In the embodiment of the present invention, the obtaining module 400 is configured to obtain an increase amount of a unit fracture area of a shale oil reservoir, where the increase amount of the unit fracture area dynamically changes according to a diffusion depth of carbon dioxide gas in a fracture of the shale oil reservoir, and the carbon dioxide gas is pre-injected into the shale oil reservoir; the first determining module 402 is configured to determine a target fracture area of the shale oil reservoir, where the target fracture area dynamically changes with a cumulative open time of the shale oil reservoir; the second determining module 404 is configured to determine an oil-up estimation result of the shale oil reservoir based on the target fracture area and the oil-up per unit fracture area; according to the oil increment evaluation result, the carbon dioxide huff-puff effect of the shale oil reservoir is determined, and the purpose of determining the carbon dioxide huff-puff effect of the shale oil reservoir by comprehensively considering the factors of gas diffusion and crack area dynamic change is achieved, so that the technical effects of improving the prediction efficiency and the prediction accuracy of the carbon dioxide huff-puff effect of the shale oil reservoir are achieved, and the technical problems that the carbon dioxide huff-puff effect of the shale oil reservoir in the related art is determined mainly by means of a conventional oil reservoir numerical simulation method, and the problems of large calculated amount, long time consumption, high difficulty in crack characterization and inaccurate evaluation are solved.
It should be noted that each of the above modules may be implemented by software or hardware, for example, in the latter case, it may be implemented by: the above modules may be located in the same processor; alternatively, the various modules described above may be located in different processors in any combination.
It should be noted that, the acquiring module 400, the first determining module 402, and the second determining module 404 correspond to steps S102 to S106 in the embodiment, and the modules are the same as the examples and application scenarios implemented by the corresponding steps, but are not limited to the disclosure of the embodiment. It should be noted that the above modules may be run in a computer terminal as part of the apparatus.
It should be noted that, the optional or preferred implementation manner of this embodiment may be referred to the related description in the embodiment, and will not be repeated herein.
The shale oil reservoir carbon dioxide huff and puff effect prediction apparatus may further include a processor and a memory, wherein the acquiring module 400, the first determining module 402, the second determining module 404 and the like are all stored in the memory as program modules, and the processor executes the program modules stored in the memory to implement corresponding functions.
The processor comprises a kernel, the kernel accesses the memory to call the corresponding program module, and the kernel can be provided with one or more than one. The memory may include volatile memory, random Access Memory (RAM), and/or nonvolatile memory, such as Read Only Memory (ROM) or flash memory (flash RAM), among other forms in computer readable media, the memory including at least one memory chip.
According to an embodiment of the present application, there is also provided an embodiment of a nonvolatile storage medium. Optionally, in this embodiment, the nonvolatile storage medium includes a stored program, where when the program runs, the device where the nonvolatile storage medium is controlled to execute any one of the shale oil reservoir carbon dioxide throughput effect prediction methods.
Alternatively, in this embodiment, the above-mentioned nonvolatile storage medium may be located in any one of the computer terminals in the computer terminal group in the computer network or in any one of the mobile terminals in the mobile terminal group, and the above-mentioned nonvolatile storage medium includes a stored program.
Optionally, the program controls the device in which the nonvolatile storage medium is located to perform the following functions when running: obtaining the oil increasing amount of a unit fracture area of a shale oil reservoir, wherein the oil increasing amount of the unit fracture area is dynamically changed along with the diffusion depth of carbon dioxide gas in a fracture of the shale oil reservoir, and the carbon dioxide gas is pre-injected into the shale oil reservoir; determining a target fracture area of the shale oil reservoir, wherein the target fracture area dynamically changes along with the accumulated open time of the shale oil reservoir; determining an oil-up evaluation result of the shale oil reservoir based on the target fracture area and the oil-up per unit fracture area; and determining the carbon dioxide huff-puff effect of the shale oil reservoir according to the oil increment evaluation result.
According to an embodiment of the present application, there is also provided an embodiment of a processor. Optionally, in this embodiment, the processor is configured to run a program, where any one of the methods for predicting a carbon dioxide throughput effect of a shale oil reservoir is executed when the program runs.
According to an embodiment of the present application, there is also provided an embodiment of a computer program product, which when executed on a data processing device, is adapted to carry out a program initializing the shale reservoir carbon dioxide throughput effect prediction method steps of any of the above.
Optionally, the computer program product mentioned above, when executed on a data processing device, is adapted to perform a program initialized with the method steps of: obtaining the oil increasing amount of a unit fracture area of a shale oil reservoir, wherein the oil increasing amount of the unit fracture area is dynamically changed along with the diffusion depth of carbon dioxide gas in a fracture of the shale oil reservoir, and the carbon dioxide gas is pre-injected into the shale oil reservoir; determining a target fracture area of the shale oil reservoir, wherein the target fracture area dynamically changes along with the accumulated open time of the shale oil reservoir; determining an oil-up evaluation result of the shale oil reservoir based on the target fracture area and the oil-up per unit fracture area; and determining the carbon dioxide huff-puff effect of the shale oil reservoir according to the oil increment evaluation result.
As shown in fig. 5, an embodiment of the present invention provides an electronic device, where the electronic device 10 includes a processor, a memory, and a program stored on the memory and executable on the processor, and the processor implements the following steps when executing the program: obtaining the oil increasing amount of a unit fracture area of a shale oil reservoir, wherein the oil increasing amount of the unit fracture area is dynamically changed along with the diffusion depth of carbon dioxide gas in a fracture of the shale oil reservoir, and the carbon dioxide gas is pre-injected into the shale oil reservoir; determining a target fracture area of the shale oil reservoir, wherein the target fracture area dynamically changes along with the accumulated open time of the shale oil reservoir; determining an oil-up evaluation result of the shale oil reservoir based on the target fracture area and the oil-up per unit fracture area; and determining the carbon dioxide huff-puff effect of the shale oil reservoir according to the oil increment evaluation result.
The foregoing embodiment numbers of the present invention are merely for the purpose of description, and do not represent the advantages or disadvantages of the embodiments.
In the foregoing embodiments of the present invention, the descriptions of the embodiments are emphasized, and for a portion of this disclosure that is not described in detail in this embodiment, reference is made to the related descriptions of other embodiments.
In the several embodiments provided in the present application, it should be understood that the disclosed technology content may be implemented in other manners. The above-described embodiments of the apparatus are merely exemplary, and the division of the modules may be a logic function division, and there may be another division manner when actually implemented, for example, a plurality of modules or components may be combined or may be integrated into another system, or some features may be omitted or not performed. Alternatively, the coupling or direct coupling or communication connection shown or discussed with respect to each other may be through some interface, module or indirect coupling or communication connection of modules, electrical or otherwise.
The modules described above as separate components may or may not be physically separate, and components shown as modules may or may not be physical modules, i.e., may be located in one place, or may be distributed over a plurality of modules. Some or all of the modules may be selected according to actual needs to achieve the purpose of the solution of this embodiment.
In addition, each functional module in each embodiment of the present invention may be integrated into one processing module, or each module may exist alone physically, or two or more modules may be integrated into one module. The integrated modules may be implemented in hardware or in software functional modules.
The integrated modules described above, if implemented in the form of software functional modules and sold or used as a stand-alone product, may be stored in a computer readable non-volatile storage medium. Based on such understanding, the technical solution of the present invention may be embodied essentially or in part or all of the technical solution or in part in the form of a software product stored in a non-volatile storage medium, including several instructions to cause a computer device (which may be a personal computer, a server, or a network device, etc.) to perform all or part of the steps of the methods of the embodiments of the present invention. And the aforementioned nonvolatile storage medium includes: a U-disk, a Read-Only Memory (ROM), a random access Memory (RAM, random AccessMemory), a removable hard disk, a magnetic disk, or an optical disk, or other various media capable of storing program codes.
The foregoing is merely a preferred embodiment of the present invention and it should be noted that modifications and adaptations to those skilled in the art may be made without departing from the principles of the present invention, which are intended to be comprehended within the scope of the present invention.
Claims (10)
1. The method for determining the carbon dioxide huff and puff effect of the shale oil reservoir is characterized by comprising the following steps of:
obtaining the oil increasing amount of a unit fracture area of a shale oil reservoir, wherein the oil increasing amount of the unit fracture area is dynamically changed along with the diffusion depth of carbon dioxide gas in a fracture of the shale oil reservoir, and the carbon dioxide gas is pre-injected into the shale oil reservoir;
determining a target fracture area of the shale oil reservoir, wherein the target fracture area dynamically changes with accumulated open time of the shale oil reservoir;
determining an oil-increasing evaluation result of the shale oil reservoir based on the target fracture area and the oil-increasing amount per unit fracture area; and determining the carbon dioxide huff and puff effect of the shale oil reservoir according to the oil increment evaluation result.
2. The method of claim 1, wherein the determining the target fracture area of the shale reservoir comprises:
obtaining production history data of the shale oil reservoir, wherein the production history data at least comprises: the shale oil reservoir corresponds to crude oil yield, water content, formation pressure and bottom hole flowing pressure;
the target fracture area is determined based on the production history data.
3. The method of claim 2, wherein the determining the target fracture area based on the production history data comprises:
calculating a plurality of crack areas at different historical moments based on the production historical data;
selecting a crack area corresponding to the water content in a first preset range from the plurality of crack areas;
and determining an average value of the crack areas corresponding to the water content in a first preset range, and taking the average value as the target crack area.
4. The method of claim 3, wherein deriving a plurality of crack areas at different historical moments based on the production history data comprises:
acquiring reservoir physical parameters, crude oil high-pressure physical parameters and accumulated well opening time corresponding to the shale oil reservoir, wherein the reservoir physical parameters at least comprise: crude oil saturation pressure, crude oil compression coefficient, formation volume coefficient and formation crude oil viscosity, wherein the reservoir physical parameters at least comprise: matrix-over-pressure permeability, matrix-over-pressure porosity, irreducible water saturation;
based on the production history data, the reservoir physical property parameters, the crude oil high-pressure physical property parameters and the accumulated well opening time, a plurality of crack areas at different historical moments are obtained in the following mode:
Wherein A is f1 Represents crack area, q at different historic moments o Representing the crude oil yield, B o Representing the formation volume coefficient, P i Representing the formation pressure, P wf Represents the bottom hole flow pressure, mu o Representing the viscosity of the crude oil of the stratum, t k Representing the cumulative open time, K representing the matrix overburden permeability, phi representing the matrix overburden porosity, C t Representing an integrated compression factor, wherein the integrated compression factor is determined based on the crude oil compression factor and the irreducible water saturation.
5. The method of claim 1, wherein the determining the oil-up evaluation of the shale reservoir based on the target fracture area and the oil-up per fracture area comprises:
acquiring the corresponding ground crude oil density of the shale oil deposit and the target diffusion distance of the carbon dioxide gas in cracks of the shale oil deposit, wherein the target diffusion distance is the distance between the position, in which the concentration of the carbon dioxide gas in the cracks of the shale oil deposit reaches a preset concentration, and the crack surface of the shale oil deposit after the carbon dioxide gas is injected into the shale oil deposit and the shale oil deposit is subjected to well soaking treatment;
And determining an oil increase evaluation result of the shale oil reservoir based on the ground crude oil density, the target diffusion distance, the target fracture area and the unit fracture area oil increase.
6. The method of claim 5, wherein the oil-up evaluation of the shale reservoir is determined based on the surface crude oil density, the target diffusion distance, the target fracture area, and the oil-up per unit fracture area by:
wherein A is f For the target fracture area ρ o For the surface crude oil density, d is the target diffusion distance, q o (x) And increasing the oil quantity for the unit crack area.
7. The method of claim 5, wherein the method further comprises:
acquiring the ground crude oil density, the diffusion depth, the matrix-based overburden porosity, the matrix-based water saturation, the crude oil volume coefficient and the crude oil volume expansion factor corresponding to the shale oil deposit, wherein the crude oil volume expansion factor is the expansion factor of the crude oil volume in the shale oil deposit compared with the expansion factor of the crude oil before the carbon dioxide gas is not injected after the carbon dioxide gas is injected into the shale oil deposit and the shale oil deposit is subjected to well soaking treatment, and the crude oil volume expansion factor is dynamically changed along with the diffusion depth of the carbon dioxide gas in cracks of the shale oil deposit;
And determining the oil increase amount per unit fracture area based on the surface crude oil density, the diffusion depth, the matrix-over-pressure porosity, the matrix-tie-water saturation, the crude oil volume coefficient and the crude oil volume expansion multiple.
8. The method of claim 7, wherein the unit fracture area enhanced oil volume is determined based on the surface crude oil density, the diffusion depth, the matrix-over-pressure porosity, the matrix-tie-water saturation, the crude oil volume coefficient, and the crude oil volume expansion multiple by:
wherein q o (x) Indicating the oil increment per unit crack area, ρ o Representing the surface crude oil density, x representing the diffusion depth, phi representing the matrix overburden porosity, S wi Representing the matrix irreducible water saturation, B o Representing the volume coefficient of the crude oil, V s (x) Indicating the volume expansion factor of the crude oil.
9. Shale oil reservoir carbon dioxide huff and puff effect prediction device, characterized by comprising:
the oil increasing unit comprises an acquisition module, a control module and a control module, wherein the acquisition module is used for acquiring the oil increasing amount of a unit fracture area of a shale oil reservoir, the oil increasing amount of the unit fracture area is dynamically changed along with the diffusion depth of carbon dioxide gas in a fracture of the shale oil reservoir, and the carbon dioxide gas is pre-injected into the shale oil reservoir;
The first determining module is used for determining a target fracture area of the shale oil reservoir, wherein the target fracture area dynamically changes along with the accumulated open time of the shale oil reservoir;
the second determining module is used for determining an oil increasing amount evaluation result of the shale oil reservoir based on the target fracture area and the oil increasing amount of the unit fracture area; and determining the carbon dioxide huff and puff effect of the shale oil reservoir according to the oil increment evaluation result.
10. A non-volatile storage medium having stored thereon a plurality of instructions adapted to be loaded by a processor and to perform the shale reservoir carbon dioxide throughput effect prediction method of any of claims 1 to 8.
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