CN109162686B - Method and device for predicting fire flooding front edge position - Google Patents
Method and device for predicting fire flooding front edge position Download PDFInfo
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- CN109162686B CN109162686B CN201810812785.0A CN201810812785A CN109162686B CN 109162686 B CN109162686 B CN 109162686B CN 201810812785 A CN201810812785 A CN 201810812785A CN 109162686 B CN109162686 B CN 109162686B
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
- E21B43/243—Combustion in situ
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/26—Storing data down-hole, e.g. in a memory or on a record carrier
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- G—PHYSICS
- G06—COMPUTING; CALCULATING OR COUNTING
- G06Q—INFORMATION AND COMMUNICATION TECHNOLOGY [ICT] SPECIALLY ADAPTED FOR ADMINISTRATIVE, COMMERCIAL, FINANCIAL, MANAGERIAL OR SUPERVISORY PURPOSES; SYSTEMS OR METHODS SPECIALLY ADAPTED FOR ADMINISTRATIVE, COMMERCIAL, FINANCIAL, MANAGERIAL OR SUPERVISORY PURPOSES, NOT OTHERWISE PROVIDED FOR
- G06Q50/00—Systems or methods specially adapted for specific business sectors, e.g. utilities or tourism
- G06Q50/02—Agriculture; Fishing; Mining
Abstract
The embodiment of the invention provides a method and a device for predicting the position of a fire flooding front edge, and belongs to the technical field of oil development. The method for predicting the position of the fire front comprises the following steps: determining the advancing distance of the fire flooding front of each oil layer in the plurality of oil layers along the direction of each production well according to the distribution angle of the central gas injection well in the direction of each production well in the target well group, the thickness of each oil layer in the plurality of oil layers of the target oil reservoir, the amount of air consumed by combustion of each oil layer per unit volume, the air intake percentage of each oil layer in the plurality of oil layers, the accumulated injection amount of the central gas injection well along the direction of each production well within a certain time period and the formation air retention rate between the central gas injection well and each production well. By the technical scheme, the propulsion distance of the fire flooding front edge of each oil layer in the oil layers can be predicted, and a basis can be provided for adjusting injection and production parameters in the multi-layer fire flooding production process.
Description
Technical Field
The invention relates to the technical field of oil development, in particular to a method and a device for predicting the position of a fire flooding front edge.
Background
In-situ combustion, also known as fire flooding, is a thermal recovery technique for increasing the recovery ratio of heavy oil reservoirs. The method comprises the steps of continuously injecting air into an oil layer and igniting the oil layer, taking a coke-like substance generated in the pyrolysis reaction process as a fuel, improving the flowability of bottom crude oil by utilizing heat generated by combustion, and driving the crude oil to be pushed to a production well by using generated carbon dioxide and nitrogen to form flue gas. During the process of stable combustion of the oil layer, the combustion zone is radially advanced to form a firing line (i.e. the position of the fire-driving front).
Due to the complex fireflood combustion reaction and the influence of stratum heterogeneity, gas channeling is easy to occur in the gas injection process, and injection and production parameters need to be adjusted in time to maintain uniform propulsion of a firing line. Therefore, the moving distance of the fire flooding front edge of each direction of the gas injection well is determined, and the method has important significance for analyzing the underground combustion state, adopting reasonable gas injection strength, timely carrying out production adjustment and improving the fire flooding development effect.
For a heavy oil reservoir developed by adopting an area well pattern multilayer fire flooding, the following two problems mainly exist in predicting the position of a fire flooding front:
(1) plane wave unevenness. The area well pattern development is adopted, due to the plane heterogeneity of a reservoir, the connectivity difference between the gas injection well and each production well in the control range of the gas injection well is large, the tail gas discharge amount of the production well with good connectivity with the gas injection well is high, the fire flooding front edge is propelled fast along the direction, the tail gas discharge amount of the well with poor connectivity is low, and the fire flooding front edge is propelled slowly along the direction. Therefore, splitting the injection amount of each direction of the gas injection well is required before predicting the position of the fire front.
(2) Uneven longitudinal movement. The multilayer fire flooding is mainly used for developing thin interbedded heavy oil reservoirs, and due to the fact that longitudinal heterogeneity is strong, interlayer difference is large, gas is injected in a cage mode, oil reservoirs with good physical properties absorb more gas, the using degree is high, oil reservoirs with poor physical properties absorb less gas, and the using degree is low. And because the number of longitudinal layers of the thin and mutually layered oil reservoir is large, and the thickness of each layer is relatively small, the difficulty in researching the fire flooding position in each oil layer of the thin and mutually layered oil reservoir is high.
The inventor of the present application has found that the conventional method for predicting the fire front position based on the material balance is directed to a single-layer homogeneous oil reservoir, does not consider the complicated situation of uneven longitudinal power utilization of a multi-layer fire drive, and does not have a technical scheme for predicting the fire drive position in the multi-layer oil reservoir.
Disclosure of Invention
It is an object of embodiments of the present invention to provide a method for predicting fire front position and an apparatus for predicting fire front position that solve the above technical problems.
In order to achieve the above object, an embodiment of the present invention provides a method for predicting a location of a fire front, the method including: determining the advancing distance of the fire flooding front of each oil layer in the plurality of oil layers along the direction of each production well according to the distribution angle of the central gas injection well in the direction of each production well in the target well group, the thickness of each oil layer in the plurality of oil layers of the target oil reservoir, the amount of air consumed by combustion of each oil layer per unit volume, the air intake percentage of each oil layer in the plurality of oil layers, the accumulated injection amount of the central gas injection well along the direction of each production well within a certain time period and the formation air retention rate between the central gas injection well and each production well.
Optionally, the method determines the advance distance of the fire front of a layer in the plurality of oil layers along the direction of each production well by the following formula:
wherein alpha isiDenotes the distribution angle, R, of the central gas injection well in the direction of the production well iikRepresents the advancing distance h of the fire flooding front in the k layer oil layer along the direction of a production well ikThickness of the k-th oil layer, AsAir amount indicating combustion of unit volume of oil layer, Ii0Representing the cumulative injection quantity, eta, of a central gas injection well in the direction of the production well i over a certain period of timekDenotes the percent of gas absorption of the k-th layer, Y denotes the oxygen utilization, wiIndicating the formation air retention between the central gas injection well and the production well i.
Optionally, determining the thickness of each reservoir in the target reservoir by: performing fine reservoir description on a target reservoir to establish a geological model corresponding to the target reservoir; and determining the thickness of each oil layer in the target oil reservoir according to the geological model.
Optionally, the amount of air consumed by combustion of said volume of reservoir is determined by: obtaining a rock core and an oil sample of a position of a target oil reservoir; and determining the air quantity consumed by combustion of the unit volume of the oil layer according to the core and the oil sample.
Optionally, the cumulative injection amount of the central gas injection well in the direction of the respective production well over a period of time is determined by: determining connectivity between each production well in the target well group and a line of gas injection wells around each production well according to daily tail gas displacement of the production wells in the target well group and daily gas injection quantity of the line of gas injection wells around each production well; determining the effective direction of each production well and the effective degree corresponding to the effective direction according to the connectivity between each production well and the line of gas injection wells around each production well; determining the cumulative exhaust gas displacement of each production well from the central gas injection well direction over a certain period of time according to the effect direction, the effect degree and the total cumulative exhaust gas displacement of each production well over the certain period of time; and determining the cumulative injection amount of the central gas injection well in the direction of each production well in the certain period of time according to the total cumulative injection amount of the central gas injection well in the certain period of time and the cumulative exhaust displacement of each production well from the direction of the central gas injection well in the certain period of time.
Optionally, the method further comprises determining connectivity between each production well in the target well group and the line of gas injection wells around the each production well by:
wherein q isi(t) represents the daily exhaust gas emission, beta, of the production well i0Representing the injection-production imbalance constant, betaijRepresents the communication coefficient i between the production well i and the gas injection well jij(t) represents the daily gas injection for gas injection well j, and n represents the number of gas injection wells in the first line around production well i.
Optionally, the method further comprises determining the cumulative exhaust gas displacement of the well over the period of time from the line of gas injection well direction around the respective production well by the formula:
wherein Q isijRepresents the cumulative exhaust gas displacement, beta, of the production well i from the direction of the gas injection well j over a certain period of timeijRepresenting production wells i andcoefficient of communication, Q, between gas injection wells jiAnd n represents the number of the first line gas injection wells around the production well i.
Optionally, the method further comprises determining a cumulative injection amount of the central gas injection well over the period of time in the direction of the respective production well by:
wherein, Ii0Represents the cumulative injection, Q, of the central gas injection well over a period of time in the direction of the production well ii0Representing the cumulative exhaust gas displacement of the production well I from the direction of the central gas injection well over a certain period of time, m representing the number of production wells in the target well group, I0Representing the total cumulative injection volume of the central gas injection well over the certain time.
Optionally, determining the formation air retention between the central gas injection well and the individual production wells by: and determining the formation air retention rate between the central gas injection well and each production well by the accumulated tail gas discharge of each production well from the central gas injection well direction in the certain time period, the accumulated injection amount of each central gas injection well along each production well direction in the certain time period and the nitrogen content.
Optionally, the method further comprises determining a formation air retention rate between the central gas injection well and the individual production wells by the following formula:wherein, wiRepresents the formation air retention, Q, between the central gas injection well and the production well ii0Represents the cumulative exhaust emission, N, of the production well i from the central gas injection well direction over a period of timeTiRepresenting the percentage of nitrogen in the tail gas of the production well i, NARepresents the percentage of nitrogen in the air injected by the gas injection well, Ii0Representing the cumulative injection of the central gas injection well over a period of time in the direction of the production well i.
Optionally, the method further includes: and determining the advancing distance of the fire flooding front in the target well group along the direction of each production well according to the advancing distance of the fire flooding front in each oil layer of the plurality of oil layers of the target oil reservoir along the direction of each production well.
Optionally, the method determines the advance distance of the fireflood front in the target well group along the direction of each production well by the following formula:
wherein R isiRepresenting the advance distance of the fireflood front in the direction of the production well i in the target well group, RikRepresents the advancing distance h of the fire flooding front in the k layer oil layer along the direction of a production well ikThe thickness of the k-th oil layer is shown, and z is the number of layers of the oil layer in the target reservoir.
Accordingly, the present invention also provides an apparatus for predicting fire front location, the apparatus comprising: a memory for storing instructions and a processor, the instructions enabling the processor to perform a method for predicting a fire front position according to embodiments of the present application.
Accordingly, the present invention also provides a machine-readable storage medium having stored thereon instructions for causing a machine to perform a method for predicting a fire front location as described in embodiments herein.
According to the technical scheme provided by the embodiment of the invention, the influences of plane wave unevenness and longitudinal utilization unevenness in the well pattern are considered, and through the technical scheme, the propulsion distance of the fire flooding front edge of each oil layer in a plurality of oil layers can be predicted, so that a basis can be provided for adjusting injection and production parameters in the production process of multilayer fire flooding. In addition, the technical scheme provided by the embodiment of the invention can also judge the communication among wells and the underground combustion state.
Additional features and advantages of embodiments of the invention will be set forth in the detailed description which follows.
Drawings
The accompanying drawings, which are included to provide a further understanding of the embodiments of the invention and are incorporated in and constitute a part of this specification, illustrate embodiments of the invention and together with the description serve to explain the embodiments of the invention without limiting the embodiments of the invention. In the drawings:
FIG. 1 is a flow chart of a method for predicting a location of a fire front in accordance with an embodiment of the present invention;
FIG. 2 is a schematic diagram of a target well group configuration provided by an embodiment of the present invention;
FIG. 3 is a schematic cross-sectional view of a reservoir provided by an embodiment of the present invention;
FIG. 4 is a schematic diagram of the effective direction and the effective degree of a production well according to an embodiment of the present invention;
FIG. 5 is a plan view of a fireflood location for a target well group provided by an embodiment of the present invention;
fig. 6 is a schematic structural diagram of an apparatus for predicting a location of a fire front according to an embodiment of the present invention.
Description of the reference numerals
1-8 production well 01 central gas injection well
02-09 adjacent gas injection well 10 storage device
20 processor
α1Distribution angle of central gas injection well along production well 1 direction
α2Distribution angle of central gas injection well along direction of production well 2
Detailed Description
The following detailed description of embodiments of the invention refers to the accompanying drawings. It should be understood that the detailed description and specific examples, while indicating embodiments of the invention, are given by way of illustration and explanation only, not limitation.
FIG. 1 is a flow chart of a method for predicting a location of a fire front in accordance with an embodiment of the present invention. As shown in fig. 1, the method may include the following steps.
In step S1, the distribution angles in the direction of each production well according to the center gas injection well in the target well group are obtained.
Wherein a central gas injection well edge in the target well groupThe distribution angle for each production well direction refers to: the included angle formed by the connecting line of the central gas injection well and the midpoint of the distance between a certain production well and two adjacent production wells. As shown in FIG. 2, the production well 1 and the production well 2 and the production well 4 respectively have their centers connected with the central gas injection well 01 to form an included angle α1. A is said1The distribution angle of the central gas injection well 01 in the direction of the production well 1 is indicated. Similarly, α2The distribution angle of the central gas injection well 01 in the direction of the production well 2. The magnitude of the distribution angle is determined by the positional relationship between the central gas injection well and each of the production wells, and after the target set of wells is determined, the distribution angle of the central gas injection well in either direction of the production wells is determined.
In step S2, the thickness of each of the plurality of oil layers of the target reservoir is acquired.
In order to solve the problem that the position of the fire flooding front in different oil layers cannot be predicted by a method in the prior art, the thickness of each oil layer in a target oil reservoir needs to be determined first, and then the position of the fire flooding front in each oil layer in the target oil reservoir can be predicted.
Specifically, the embodiment of the present invention further provides a method for determining the thickness of each oil layer in a target oil reservoir, which includes: and carrying out fine reservoir description on the target reservoir to establish a geological model corresponding to the target reservoir, and determining the thickness of each oil layer in the target reservoir according to the geological model.
The oil reservoir description refers to quantitative description and characterization of various characteristics of an oil reservoir in a three-dimensional space, and qualitatively and quantitatively describes parameters such as oil reservoir types, external geometric shapes, scale sizes, oil reservoir internal structures and the like in the three-dimensional space by integrating various theories and subject methods. When oil exploration and exploitation are carried out, oil reservoir description is an essential step, and the technical scheme provided by the embodiment of the invention only needs to obtain the thickness of each oil reservoir in the established geological model.
In step S3, the amount of air consumed by combustion of the unit volume of the oil layer is acquired.
In the technical scheme provided by the embodiment of the invention, the air quantity consumed by combustion of the unit volume of the oil layer is determined. In this embodiment of the present invention, there is also provided a method for determining the amount of air consumed by combustion per volume of a reservoir: the method comprises the steps of firstly obtaining a core and an oil sample of a position of a target oil reservoir, and determining the air quantity consumed by combustion of an oil layer in unit volume according to the core and the oil sample.
For example, subterranean cores and oil samples may be drilled through equipment such as coring wells. After identifying, analyzing and testing the physical model formed by the rock core and the oil sample, the worker can measure the air consumed by combustion of the oil layer in unit volume by the conventional testing means.
Alternatively, the amount of air consumed by combustion of a unit volume of reservoir may be determined by sand and oil samples.
In step S4, the inhalation percentage for each of the plurality of oil layers is obtained.
During the development of firefloods, the propulsion distance of the firing line is affected by the air suction capacity of the oil reservoir. Therefore, the percent of inspiration for each reservoir in the longitudinal direction can be analyzed and determined by the inspiration profile test data. The operator can determine the difference of the air suction capacity of each oil layer according to the air suction percentage of each oil layer.
In step S5, the cumulative injection amount of the central gas injection well in each production well direction over a certain period of time is obtained.
Embodiments of the present invention provide a method for determining cumulative injection volume of a central gas injection well over a period of time in each production well direction, comprising:
determining connectivity between each production well and a first-line gas injection well around each production well according to daily tail gas discharge of the production wells and daily gas injection quantity of the first-line gas injection well around each production well;
determining the effective direction of each production well and the effective degree corresponding to the effective direction according to the connectivity between each production well and a line of gas injection wells around each production well;
determining the accumulated tail gas discharge of each production well from the direction of the central gas injection well in a certain time period according to the effective direction, the effective degree and the total accumulated tail gas discharge of each production well in the certain time period; and
and determining the accumulated injection amount of the central gas injection well in the direction of each production well in the certain time period according to the total accumulated injection amount of the central gas injection well in the certain time period and the accumulated tail gas discharge amount of each production well from the direction of the central gas injection well in the certain time period.
Alternatively, the connectivity between the central gas injection well and each production well may also be determined by the daily gas injection rate of the central gas injection well and the daily liquid production rate of the production wells (including daily oil production and daily water production).
However, due to the particularity of exploiting the oil deposit by the fireflood technology, the change of the liquid production amount of the production well caused by the change of the gas injection amount of the gas injection well can delay, generally for several months, and therefore, the acquisition of quick response data is not facilitated. In the technical scheme provided by the embodiment of the invention, the gas injection quantity of the gas injection well has a relatively quick influence on the tail gas discharge capacity of the production well, and if the correlation between the gas injection quantity and the tail gas discharge capacity is good, the communication between the corresponding gas injection well and the production well is good.
Accordingly, embodiments of the present invention also provide a formula for determining connectivity between each production well in a target well group and a line of gas injection wells around each production well:
qi(t) represents the daily exhaust gas emission, beta, of the production well i0Representing the injection-production imbalance constant, betaijThe communication coefficient between the production well i and the gas injection well j is represented, namely the communication coefficient between the production well i and the gas injection well j, iij(t) represents the daily gas injection quantity of gas injection well j, and n represents the number of gas injection wells in the line around producing well i (for example, as shown in FIG. 2, the gas injection wells in the line around producing well 1 are central gas injection well 01, adjacent gas injection well 02, adjacent gas injection well 03, and adjacent gas injection well 05, so n is 4, and the gas injection wells in the line around producing well 2 are central gas injection well 01 and adjacent gas injection well 03, so n is 2).
Wherein the day of production well iExhaust gas discharge qi(t), daily gas injection amount i of gas injection well jij(t) and the number n of gas injection wells in the line around the production well i are known during the performance of the oil recovery operation.
If the communication coefficient between the central gas injection well and each production well is to be determined, daily tail gas discharge of each production well and daily gas injection quantity of a first-line gas injection well around each production well are required to be substituted into the formula for determining the communication, and a determination result is calculated through a matrix. For example, as shown in fig. 2, the daily tail gas discharge capacity of the production well 1, the daily gas injection amount of the central gas injection well 01, the daily gas injection amount of the adjacent gas injection well 02, the daily gas injection amount of the adjacent gas injection well 03 and the daily gas injection amount of the adjacent gas injection well 05 are substituted into the above formula, and the communication coefficient between the production well 1 and the central gas injection well 01 can be determined through calculation, and meanwhile, the communication coefficients between the production well 1 and the adjacent gas injection well 02, the adjacent gas injection well 03 and the adjacent gas injection well 05 can also be determined.
In addition, the effective direction mentioned in the embodiment of the present invention refers to the direction from the gas injection well j to the production well i, and the effective degree corresponding to the effective direction indicates the proportion of the tail gas from the gas injection well j in the tail gas discharged from the production well i.
Accordingly, embodiments of the present invention also provide a formula for determining the cumulative exhaust emissions of each production well from the first line gas injection well direction around each production well over the certain time period:
wherein Q isijRepresents the cumulative exhaust gas displacement, beta, of the production well i from the direction of the gas injection well j over a certain period of timeijRepresents the communication coefficient, Q, between the production well i and the gas injection well jiAnd n represents the number of the first line gas injection wells around the production well i.
Wherein the total accumulated tail gas discharge Q of the production well i in the certain time periodiAnd the number n of gas injection wells in the line around the production well i are known during the oil production work. Communication coefficient beta between production well i and gas injection well jijThe method can be determined by the method provided by the embodiment of the invention, or by any one of the existing technical means.
Accordingly, embodiments of the present invention also provide a formula for determining a cumulative injection amount of a central gas injection well in each production well direction over the certain time period:
wherein, Ii0Represents the cumulative injection, Q, of the central gas injection well over a period of time in the direction of the production well ii0Representing the cumulative exhaust gas displacement of the production well I from the direction of the central gas injection well over a certain period of time, m representing the number of production wells in the target well group, I0Representing the total cumulative injection volume of the central gas injection well over the certain time.
Wherein the production well i is from the direction of the central gas injection well and the accumulated tail gas discharge Q in a certain period of timei0The cumulative exhaust gas displacement during the certain time period for each production well from the direction of the line of gas injection wells around each production well can be determined by calculation according to the above formula provided by the embodiment of the invention, and the total cumulative injection amount I of the central gas injection well during the certain time period0Are known in the art during the performance of oil recovery operations.
In addition, the "certain time period" mentioned in the embodiment of the present invention may be set by the operator according to the actual working requirement.
In step S6, formation air retention rates between the central gas injection well and the individual production wells are obtained.
The embodiment of the invention provides a method for determining the stratum air retention rate between a central gas injection well and each production well by the following steps:
acquiring the accumulated tail gas discharge of each production well from the direction of a central gas injection well within a certain time period;
acquiring the accumulated injection amount of the central gas injection well in a certain time period along the direction of each production well;
acquiring nitrogen content, including nitrogen content in tail gas discharged by a production well and content in air injected by a central gas injection well; and
and determining the stratum air retention rate between the central gas injection well and each production well according to the acquired data.
Correspondingly, the embodiment of the invention also provides a formula for determining the formation air retention rate between the central gas injection well and each production well:
wherein, wiRepresents the formation air retention, Q, between the central gas injection well and the production well ii0Represents the cumulative exhaust emission, N, of the production well i from the central gas injection well direction over a period of timeTiRepresenting the percentage of nitrogen in the tail gas of the production well i, NARepresents the percentage of nitrogen in the air injected by the gas injection well, Ii0Representing the cumulative injection of the central gas injection well over a period of time in the direction of the production well i.
Wherein the production well i is from the direction of the central gas injection well and the accumulated tail gas discharge Q in a certain period of timei0And the cumulative injection I of the central gas injection well in the direction of the production well I over a certain period of timei0The determination can be performed according to the method provided by the embodiment of the invention, and the determination can also be performed by other methods.
Wherein, in the process of exploiting the oil reservoir by utilizing the fireflood technology, the nitrogen does not participate in the combustion reaction. The percentage of nitrogen content in the air injected by the gas injection well is known and, depending on the amount of air injected, the total amount of nitrogen injected can be determined. The total amount of nitrogen in the exhaust gas can be determined from the total amount of exhaust gas and the ratio of the measured nitrogen in the exhaust gas. And determining the retention rate of the air in the stratum according to the difference between the total amount of the injected nitrogen and the total amount of the exhausted nitrogen.
The order of the above steps S1-S6 is not limited to the order shown in the embodiments of the present invention, and the required data may be acquired in any order according to actual situations.
In step S7, an advancing distance of the fire flooding front of each of the plurality of oil layers in the direction of the respective production well is determined according to a distribution angle of the central gas injection well in the direction of the respective production well in the target well group, a thickness of each of the plurality of oil layers of the target oil reservoir, an amount of air consumed by combustion of the oil layer per unit volume, a percentage of air absorption of each of the plurality of oil layers, a cumulative injection amount of the central gas injection well in the direction of the respective production well over a certain period of time, and a formation air retention rate between the central gas injection well and the respective production well.
Embodiments of the present invention also provide a formula for determining a push distance of a fire front for each of a plurality of reservoirs in a direction of a respective production well:
wherein alpha isiDenotes the distribution angle, R, of the central gas injection well in the direction of the production well iikRepresents the advancing distance h of the fire flooding front in the k layer oil layer along the direction of a production well ikThickness of the k-th oil layer, AsAir amount indicating combustion of unit volume of oil layer, Ii0Representing the cumulative injection quantity, eta, of a central gas injection well in the direction of the production well i over a certain period of timekDenotes the percent of gas absorption of the k-th layer, Y denotes the oxygen utilization, wiIndicating the formation air retention between the central gas injection well and the production well i.
The specific numerical values of the parameters in the above formula can be determined by the method provided by the embodiment of the present invention, or can be determined by other existing methods.
Optionally, in order to provide more meaningful reference data for oil production work, embodiments of the present invention provide a technical solution for determining a driving distance of a fire front in a target well group in a direction of a respective production well according to a determined driving distance of the fire front in the direction of the respective production well for each of a plurality of oil zones of the target well group.
Correspondingly, the embodiment of the invention also provides a method for processing the dataA formula for determining the distance of advance of a fireflood front in each production well direction in a target well group:
wherein R isiRepresenting the advance distance of the fireflood front in the direction of the production well i in the target well group, RikRepresents the advancing distance h of the fire flooding front in the k layer oil layer along the direction of a production well ikThe thickness of the k-th oil layer is shown, and z is the number of layers of the oil layer in the target reservoir.
Preferably, the technical scheme provided by the embodiment of the invention is suitable for the target oil reservoir meeting the following conditions: the boundary of the oil layer is shielded by faults and lithology and is not connected with a water body; the number of the oil layer layers is more than 1, and the average single-layer thickness is more than 1 m; the interlayer is continuously distributed; the average oil saturation is more than 35%; an average porosity greater than 18%; the viscosity of the crude oil in the stratum is less than 10000 Pa.S; the average permeability is greater than 200 mD.
Preferably, the target well group satisfies the following condition: well pattern area development is adopted, and well spacing is less than 200 m; the gas injection well is continuously injected without long-term shutdown, and the gas injection strength is more than 200m3V (d · m); the average oxygen utilization rate of the production well is more than 85 percent, and the average tail gas carbon dioxide content is more than 12 percent.
In order to facilitate understanding of the technical solutions provided by the embodiments of the present invention, a specific embodiment is provided to explain the technical solutions of the present invention in detail.
(1) Selecting a target oil reservoir and a target well group: the target oil reservoir is located in a certain oil field in the east of China, is a middle-deep layer thin interbedded common heavy oil reservoir, has a buried depth of 800-1200 m, and a target layer comprises 20-40 oil layers of 4 sandstone groups, and has good development of an oil layer interval layer and good boundary closure. The average porosity of the oil reservoir is 19.3%, the average permeability is 774mD, the average oil saturation is 40%, and the viscosity of the crude oil in the stratum is 1800 Pa.S. The schematic structure diagram of the target well group is shown in fig. 2, the target well group is developed by adopting a 100m 141m square inverse nine-point well pattern, the oil layer permeability profile is shown in fig. 3, the target well group longitudinally comprises 13 oil layers, the average single-layer thickness is 2.3m, and the central gas injection well 01 cumulatively injects air 22.81 106m3Average gas injection intensity of 271m3And/(d.m), the average oxygen utilization rate of the production well is 93%, and the average tail gas carbon dioxide content is 18%. Wherein the corresponding permeability of each oil layer can be determined according to the gray scale of the image of the oil layer in the cross-sectional view shown in fig. 3, corresponding to the scale on the right side of fig. 3.
(2) Developing physical simulation research in a fireflood chamber by using rock cores and oil samples obtained in the development process, and measuring the air consumption of an oil layer in unit volume of combustion to be 248m3/m3。
(3) And judging the effective direction and the effective range of each production well in the target well group according to the daily tail gas discharge data of the production wells in the target well group and the daily gas injection data of the injection wells in the target well group and the adjacent well groups, and calculating the tail gas contribution of each effective direction of the production wells in the target well group by adopting the method provided by the embodiment of the invention. According to the tail gas contribution amount of each effective direction of the production well and the total tail gas contribution amount, the tail gas contribution rate of each effective direction can be determined, and the analysis and calculation results are shown in fig. 4. Wherein the cumulative time provided by this embodiment of the invention is 12 years. The cumulative injection quantities of the central gas injection well 01, the gas injection well 02, the gas injection well 03, the gas injection well 04, the gas injection well 05, the gas injection well 06, the gas injection well 07, the gas injection well 08 and the gas injection well 09 are respectively as follows: 22.81X 106m3、23.10×106m3、19.76×106m3、21.12×106m3、0.92×106m3、21.16×106m3、20.03×106m3、0.04×106m3And 17.38X 106m3. The cumulative exhaust emissions of the production well 1, the production well 2, the production well 3, the production well 4, the production well 5, the production well 6, the production well 7 and the production well 8 are respectively as follows: 6.37X 106m3、4.37×106m3、4.78×106m3、4.28×106m3、7.51×106m3、0.63×106m3、1.86×106m3And 0.44X 106m3. The central gas injection well 01 is determined by calculation to the production well 1, the production well 2 and the production wellThe tail gas contribution rates of the well 3, the production well 4, the production well 5, the production well 6, the production well 7 and the production well 8 are respectively as follows: 74.2%, 35.2%, 13.4%, 91.3%, 82.1%, 67.9%, 93.3% and 13.9%. In addition, the tail gas contribution rates of gas injection well 02, gas injection well 03 and gas injection well 05 to production well 1 can also be determined as follows: 6.4%, 14.8% and 4.6%; the gas injection well 03 has a tail gas contribution rate of 64.8% to the production well 2; the gas injection well 03, 04, and 06 have tail gas contributions to production well 3 of 4.5%, 79.1%, and 3%; the gas injection well 05 has a tail gas contribution rate of 8.7% to the production well 4; the gas injection well 06 has a tail gas contribution rate of 17.9% to the production well 5; the gas injection well 05, gas injection well 06, and gas injection well 08 contribute 1.2%, 21%, and 9.9% to the tail gas of the production well 6; the gas injection well 08 has a tail gas contribution rate of 6.7% to the production well 7; gas injection well 06, gas injection well 08, and gas injection well 09 have tail gas contributions to production well 8 of 23.6%, 10.2%, and 52.3%.
(4) And judging the inter-well connectivity in the target well group according to the tail gas contribution amount of the gas injection well in the target well group to each production well, and splitting the air injection amount of the gas injection well along each production well direction. And determining the gas injection proportion of the central gas injection well to each production well direction according to the total air injection quantity of each production well and the air injection quantity of the central gas injection well. After analysis and calculation, the gas injection proportion of the central gas injection well 01 along the directions of the production well 1, the production well 2, the production well 3, the production well 4, the production well 5, the production well 6, the production well 7 and the production well 8 is determined as follows: 25.6%, 8.3%, 3.5%, 19.5%, 29.3%, 2.3%, 9.4% and 1.9%. According to the technical scheme provided by the embodiment of the invention, the average formation air retention rate of the injected air is determined to be 24.5%.
(5) And analyzing the air suction capability of each oil layer in the longitudinal direction according to the air suction profile test data. The air suction percentages of the oil layers 1-11 are respectively: 6%, 8%, 24%, 12%, 9%, 3%, 18%, 0%, 5%, 6% and 9%, the oil layer 11 imbibes 9% of the total imbibition volume of the oil layers 11-13 due to the instrument encounter down to the oil layer 11.
(6) By adopting the method for predicting the fire flooding front edge position provided by the embodiment of the invention, the fire line propulsion distance in each production well direction is calculated. And drawing a plan view of the fire flooding front position of the target well group according to the related data obtained by calculation, as shown in figure 5.
Where the average position of the fire front for layers 1-13 of the reservoir is shown in figure 5. According to the technical scheme of the embodiment of the invention, the position of the fire front in each oil layer can be calculated and determined according to actual needs, and a plan view of the position of the fire front in a single oil layer is drawn.
According to the method for predicting the fire flooding front edge position, the influences of plane wave unevenness and longitudinal utilization unevenness in the well pattern are comprehensively considered, the propelling position of the multilayer fire flooding is predicted by analyzing the connectivity among wells in the target well group and the air suction capacity of each oil layer, and a basis is provided for regulation and control of injection and production parameters in the production process of the multilayer fire flooding.
Fig. 6 is a schematic structural diagram of an apparatus for predicting a location of a fire front according to an embodiment of the present invention. As shown in fig. 6, the embodiment of the present invention further provides an apparatus for predicting the location of a fire front, which includes a memory 10 and a processor 20. Wherein the memory 10 is connected to the processor 20, the memory 10 is used for storing instructions for enabling the processor 20 to execute any method for predicting the location of the fire front according to the embodiment of the present invention.
Alternatively, the processor 20 may be a general purpose processor, a special purpose processor, a conventional processor, a Digital Signal Processor (DSP), a plurality of microprocessors, one or more microprocessors in association with a DSP core, a controller, a microcontroller, an Application Specific Integrated Circuit (ASIC), a Field Programmable Gate Array (FPGA) Circuit, any other type of Integrated Circuit (IC), an embedded processor, or the like that may implement the above-described functionality.
For specific details and benefits of the apparatus for predicting the location of a fire front according to the present invention, reference may be made to the above description of the method for predicting the location of a fire front according to the present invention, and further description is omitted here.
Accordingly, the embodiment of the invention also provides a machine-readable storage medium, wherein the machine-readable storage medium is stored with instructions for causing a machine to execute the method for predicting the position of the fire front edge provided by the embodiment of the invention.
Although the embodiments of the present invention have been described in detail with reference to the accompanying drawings, the embodiments of the present invention are not limited to the details of the above embodiments, and various simple modifications can be made to the technical solutions of the embodiments of the present invention within the technical idea of the embodiments of the present invention, and the simple modifications all belong to the protection scope of the embodiments of the present invention.
It should be noted that the various features described in the above embodiments may be combined in any suitable manner without departing from the scope of the invention. In order to avoid unnecessary repetition, the embodiments of the present invention do not describe every possible combination.
Those skilled in the art will understand that all or part of the steps in the method according to the above embodiments may be implemented by a program, which is stored in a storage medium and includes several instructions to enable a single chip, a chip, or a processor (processor) to execute all or part of the steps in the method according to the embodiments of the present application. And the aforementioned storage medium includes: a U-disk, a removable hard disk, a Read-Only Memory (ROM), a Random Access Memory (RAM), a magnetic disk or an optical disk, and other various media capable of storing program codes.
In addition, any combination of various different implementation manners of the embodiments of the present invention is also possible, and the embodiments of the present invention should be considered as disclosed in the embodiments of the present invention as long as the combination does not depart from the spirit of the embodiments of the present invention.
Claims (11)
1. A method for predicting fire front location, the method comprising:
determining a pushing distance of a fire flooding front of each oil layer in the plurality of oil layers along the direction of each production well according to a distribution angle of a central gas injection well in the direction of each production well in a target well group, a thickness of each oil layer in the plurality of oil layers of a target oil reservoir, an amount of air consumed by combustion of each oil layer per unit volume, a percentage of air intake of each oil layer in the plurality of oil layers, a cumulative injection amount of the central gas injection well along the direction of each production well within a certain period of time and a formation air retention rate between the central gas injection well and each production well,
wherein the advance distance of the fire front of a layer in the plurality of oil layers along the direction of each production well is determined by the following formula:
wherein alpha isiDenotes the distribution angle, R, of the central gas injection well in the direction of the production well iikRepresents the advancing distance h of the fire flooding front in the k layer oil layer along the direction of a production well ikThickness of the k-th oil layer, AsAir amount indicating combustion of unit volume of oil layer, Ii0Representing the cumulative injection quantity, eta, of a central gas injection well in the direction of the production well i over a certain period of timekDenotes the percent of gas absorption of the k-th layer, Y denotes the oxygen utilization, wiIndicating the formation air retention between the central gas injection well and the production well i,
wherein the formation air retention between the central gas injection well and the individual production wells is determined by: determining a formation air retention rate between the central gas injection well and each production well according to the accumulated tail gas displacement of each production well from the central gas injection well direction in the certain time period, the accumulated injection amount of the central gas injection well in each production well direction in the certain time period and the nitrogen content,
wherein the cumulative injection amount of the central gas injection well over a period of time in the direction of the respective production well is determined by: determining connectivity between each production well in the target well group and a line of gas injection wells around each production well according to daily tail gas displacement of the production wells in the target well group and daily gas injection quantity of the line of gas injection wells around each production well; determining the effective direction of each production well and the effective degree corresponding to the effective direction according to the connectivity between each production well and the line of gas injection wells around each production well; determining the cumulative exhaust gas displacement of each production well from the central gas injection well direction over a certain period of time according to the effect direction, the effect degree and the total cumulative exhaust gas displacement of each production well over the certain period of time; and determining the cumulative injection amount of the central gas injection well in the direction of each production well in the certain period of time according to the total cumulative injection amount of the central gas injection well in the certain period of time and the cumulative exhaust displacement of each production well from the direction of the central gas injection well in the certain period of time.
2. The method of claim 1, wherein the thickness of each reservoir in the target reservoir is determined by:
performing fine reservoir description on a target reservoir to establish a geological model corresponding to the target reservoir; and
and determining the thickness of each oil layer in the target oil reservoir according to the geological model.
3. The method of claim 1, wherein the amount of air consumed for combustion of the volume of reservoir is determined by:
obtaining a rock core and an oil sample of a position of a target oil reservoir; and
and determining the air quantity consumed by combustion of the unit volume of the oil layer according to the core and the oil sample.
4. The method of claim 1, further comprising determining connectivity between each production well in the target well group and the line of gas injection wells around the each production well by:
wherein q isi(t) represents the daily exhaust gas emission, beta, of the production well i0Representing the injection-production imbalance constant, betaijRepresents the communication coefficient i between the production well i and the gas injection well jij(t) represents the daily gas injection for gas injection well j, and n represents the number of gas injection wells in the first line around production well i.
5. The method of claim 4, further comprising determining a cumulative exhaust displacement over the period of time for the respective production well from a line of gas injection well direction around the respective production well by:
wherein Q isijRepresents the cumulative exhaust gas displacement, beta, of the production well i from the direction of the gas injection well j over a certain period of timeijRepresents the communication coefficient, Q, between the production well i and the gas injection well jiAnd n represents the number of the first line gas injection wells around the production well i.
6. The method of claim 5, further comprising determining a cumulative injection amount of the central gas injection well over the period of time in the direction of the respective production well by:
wherein, Ii0Represents the cumulative injection, Q, of the central gas injection well over a period of time in the direction of the production well ii0Representing the cumulative exhaust gas displacement of the production well i from the direction of the central gas injection well over a certain period of time, and m representing the endogenous production of the target well groupNumber of producing wells, I0Representing the total cumulative injection volume of the central gas injection well over the certain time.
7. The method of claim 1, further comprising determining a formation air retention between the central gas injection well and the individual production wells by the formula:
wherein, wiRepresents the formation air retention, Q, between the central gas injection well and the production well ii0Represents the cumulative exhaust emission, N, of the production well i from the central gas injection well direction over a period of timeTiRepresenting the percentage of nitrogen in the tail gas of the production well i, NARepresents the percentage of nitrogen in the air injected by the gas injection well, Ii0Representing the cumulative injection of the central gas injection well over a period of time in the direction of the production well i.
8. The method of claim 1, further comprising:
and determining the advancing distance of the fire flooding front in the target well group along the direction of each production well according to the advancing distance of the fire flooding front in each oil layer of the plurality of oil layers of the target oil reservoir along the direction of each production well.
9. The method of claim 8, wherein the method determines the distance of advance of the fireflood front in the target well group in the direction of the respective production well by the formula:
wherein R isiRepresenting the advance distance of the fireflood front in the direction of the production well i in the target well group, RikRepresenting the fire-flooding front in the kth layer of reservoir along the i-square of the production wellForward propulsion distance, hkThe thickness of the k-th oil layer is shown, and z is the number of layers of the oil layer in the target reservoir.
10. An apparatus for predicting fire front location, the apparatus comprising: a memory for storing instructions and a processor, the instructions enabling the processor to perform the method for predicting a fire front position according to any one of claims 1 to 9.
11. A machine-readable storage medium having instructions stored thereon for causing a machine to perform the method for predicting fire front location of any one of claims 1-9 herein above.
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| CN113137218B (en) * | 2020-01-16 | 2023-05-26 | 中国石油天然气股份有限公司 | Method and device for determining position of fire flooding front edge of fire flooding gas injection well |
| CN113622886A (en) * | 2020-04-22 | 2021-11-09 | 中国石油天然气股份有限公司 | Horizontal well fire flooding combustion front edge prediction method |
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| CN114060021B (en) * | 2020-08-06 | 2023-09-26 | 中国石油天然气股份有限公司 | Method and device for determining propelling distance of firing line of each oil layer of thin interbed heavy oil reservoir |
| CN113294133B (en) * | 2020-08-19 | 2023-05-26 | 中国石油天然气股份有限公司 | Method and system for determining fire flooding front edge in fire flooding well pattern |
| CN112502680A (en) * | 2020-11-19 | 2021-03-16 | 中国石油天然气股份有限公司 | Method for judging fireflood combustion state |
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