Method for identifying water flow dominant channel of glutenite oil reservoir

Abstract

The invention provides a glutenite reservoir water flow dominant channel identification method. The glutenite oil reservoir water flow dominant channel identification method comprises the following steps: performing clustering analysis on an oil reservoir by using a gamma and density electrical logging curve, and establishing a physical property-lithology identification chart; determining an identification standard of the water flow dominant channel according to the physical property-lithology identification chart; wherein the identification standard of the water flow dominant channel comprises gamma gt; 57 API; density lt; 2.33 g / cm < 3 >; permeability gt; 190mD, 190mD; the porosity is gt; and 16%. According to the invention, the problem that the oil reservoir water flow dominant channel cannot be accurately identified in the prior art is solved.

Description

Technical Field

[0001] The invention relates to the technical field of oil reservoir development, and in particular to a method for identifying a dominant water flow channel in a sandstone conglomerate oil reservoir. Background Art

[0002] The dominant water flow channel is a low-resistance seepage channel formed locally in the reservoir due to geology and development. In the later stage of water injection development, the injected water forms an obvious dominant flow along this channel, resulting in an invalid water injection cycle. The dominant water flow channel causes poor water drive effect, and the predicted final recovery rate is far lower than the calibrated recovery rate. The dominant water flow channel is not clearly understood, and it is difficult to carry out targeted injection and production regulation and reasonably block the water channel, which seriously affects the development effect of the reservoir. However, there are relatively few mature technologies for identifying dominant water flow channels, and there is no unified standard for the identification method. Overall, it is still in its infancy, making it impossible to accurately identify the dominant water flow channel.

[0003] It can be seen from the above that the existing technology has the problem of being unable to accurately identify the dominant channel of water flow in the oil reservoir. Summary of the invention

[0004] The main purpose of the present invention is to provide a method for identifying a dominant water flow channel in a sandstone conglomerate reservoir, so as to solve the problem that the prior art cannot accurately identify the dominant water flow channel in the reservoir.

[0005] In order to achieve the above-mentioned object, the present invention provides a method for identifying a water flow dominant channel in a sandstone conglomerate reservoir, comprising: clustering analysis of the reservoir using gamma and density electrical logging curves to establish a physical property-lithology identification chart; determining the identification criteria of the water flow dominant channel according to the physical property-lithology identification chart; wherein the identification criteria of the water flow dominant channel include: gamma>57API; density<2.33g / cm 3 ; Permeability>190mD; Porosity>16%.

[0006] Furthermore, the identification method also includes: using the liquid production and absorption profile to determine the level of the dominant water flow channel.

[0007] Furthermore, the level of the dominant water flow channel is determined by using the production and absorption profile, including: digital processing of the isotope logging tracer GR curve of the water absorption profile, and vertical grid precision division of the development section of the oil reservoir; splitting the relative water absorption of each layer according to the amount of tracer GR, and calculating the relative water absorption of each layer in the vertical direction; performing probability statistics based on the relative water absorption of each layer after splitting, and the inflection point is the dominant water flow channel of different levels.

[0008] Furthermore, the levels of water flow dominant channels include first-level dominant channels, second-level dominant channels and third-level dominant channels, among which the relative water absorption ratio of the first-level dominant channels is greater than 4%; the relative water absorption ratio of the second-level dominant channels is greater than or equal to 2% and less than or equal to 4%; the relative water absorption ratio of the third-level dominant channels is less than 2%.

[0009] Furthermore, the permeability of the first-level dominant channel is greater than 500mD; the permeability of the second-level dominant channel is greater than 100mD and less than or equal to 500mD; and the permeability of the third-level dominant channel is greater than 10mD and less than or equal to 100mD.

[0010] Furthermore, the permeability difference of the first-level dominant channel is greater than 7, the permeability variation coefficient is greater than 0.7, and the permeability breakthrough coefficient is greater than 4; the permeability difference of the second-level dominant channel is greater than or equal to 3 and less than or equal to 7, the permeability variation coefficient is greater than or equal to 0.3 and less than or equal to 0.7, and the permeability breakthrough coefficient is greater than or equal to 2 and less than or equal to 4; the permeability difference of the third-level dominant channel is less than 3, the permeability variation coefficient is less than 0.3, and the permeability breakthrough coefficient is greater than 4.

[0011] Furthermore, the identification method also includes: using the grey correlation coefficient, the inter-well seepage resistance and the rank correlation coefficient to calculate the correlation between the water injection volume of the water injection well and the liquid production volume of the oil production well, and determine the volume of the dominant water flow channel.

[0012] Furthermore, the calculation formula of the grey relational coefficient is:

[0013]

[0014] in, is the monthly injection volume sequence of the central injection well; is the monthly liquid production sequence of the surrounding effective oil-producing wells; k is the monthly data sequence number, i is the oil-producing well sequence number; ξ i (k) is the correlation coefficient between the water well in the kth month and the i-th oil producing well; ρ is the resolution factor.

[0015] Furthermore, the calculation formula of the interwell seepage resistance is:

[0016]

[0017] R oi =1 / (K oi h oi );

[0018] R wi =1 / (K wi h wi );

[0019] Among them, R tis the inter-well seepage resistance; N is the number of connected layers; i is the serial number of the connected layer; K oi is the permeability of the oil producing well at the i-th connected layer; h oi is the thickness of the i-th connected layer; K wi is the permeability of the injection well at the i-th connected layer; h wi is the thickness of the injection well at the i-th connected layer; R oi is the resistance of the oil producing well at the i-th connected layer; R wi is the resistance of the injection well at the i-th connected layer.

[0020] Furthermore, the calculation formula of the rank correlation coefficient is:

[0021]

[0022] d i =x i -y i ;

[0023] Among them, r s is the rank correlation coefficient; n is the number of samples; i is the sample number; x i is the monthly water injection volume of the injection well; i It is the monthly liquid production of surrounding effective oil producing wells.

[0024] The method for identifying the dominant water flow channel in the sandstone conglomerate reservoir by applying the technical solution of the present invention comprises: clustering analysis of the reservoir strata by using gamma and density electrical logging curves to establish a physical property-lithology identification chart; determining the identification criteria of the dominant water flow channel according to the physical property-lithology identification chart; wherein the identification criteria of the dominant water flow channel include: gamma>57API; density<2.33g / cm 3 ; Permeability>190mD; Porosity>16%. Gamma and density electrical curves are the most sensitive electrical responses to physical properties. Through the above electrical curves, an accurate physical property-lithology identification chart can be established to determine the four identification criteria for dominant water flow channels. According to the above identification criteria, the dominant water flow channels in the oil reservoir can be accurately determined, and the accurate identification of the dominant water flow channels in the oil reservoir is realized, which solves the problem that the prior art cannot accurately identify the dominant water flow channels in the oil reservoir. BRIEF DESCRIPTION OF THE DRAWINGS

[0025] The drawings constituting a part of the present application are used to provide a further understanding of the present invention. The exemplary embodiments of the present invention and their descriptions are used to explain the present invention and do not constitute an improper limitation of the present invention. In the drawings:

[0026] Figure 1 A flow chart showing a method for identifying a dominant water flow channel in a conglomerate reservoir in a specific embodiment of the present invention;

[0027] Figure 2 A schematic diagram of a lithology plate of an oil reservoir in a specific embodiment of the present invention is shown;

[0028] Figure 3 A physical property-lithology identification plate of an oil reservoir in a specific embodiment of the present invention is shown;

[0029] Figure 4 A lithology and physical property plate of an oil reservoir in a specific embodiment of the present invention is shown;

[0030] Figure 5 A relative water absorption cumulative probability diagram of an oil reservoir in a specific embodiment of the present invention is shown;

[0031] Figure 6 A diagram showing the interlayer connectivity relationship of oil and water wells in a specific embodiment of the present invention is shown. DETAILED DESCRIPTION

[0032] It should be noted that, in the absence of conflict, the embodiments and features in the embodiments of the present application can be combined with each other. The present invention will be described in detail below with reference to the accompanying drawings and in combination with the embodiments.

[0033] It should be noted that, unless otherwise specified, all technical and scientific terms used in this application have the same meanings as commonly understood by ordinary technicians in the technical field to which this application belongs.

[0034] In the present invention, unless otherwise specified, the directional words used, such as "up, down, top, bottom", usually refer to the directions shown in the drawings, or to the components themselves in the vertical, perpendicular or gravity directions; similarly, for ease of understanding and description, "inside and outside" refer to the inside and outside relative to the outline of each component itself, but the above-mentioned directional words are not used to limit the present invention.

[0035] Obviously, the above-described embodiments are only a part of the embodiments of the present invention, rather than all the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work should fall within the scope of protection of the present invention.

[0036] In order to solve the problem that the prior art cannot accurately identify the dominant water flow channel in the oil reservoir, the present invention provides a method for identifying the dominant water flow channel in the sandstone conglomerate oil reservoir.

[0037] like Figure 1As shown in the figure, the identification method of the dominant water flow channel in the sandstone conglomerate reservoir includes: clustering analysis of the reservoir using gamma and density electrical curves to establish a physical property-lithology identification chart; determining the identification criteria of the dominant water flow channel based on the physical property-lithology identification chart; wherein the identification criteria of the dominant water flow channel include: gamma>57API; density<2.33g / cm 3 ; Permeability>190mD; Porosity>16%.

[0038] The identification method of the water flow dominant channel in the sandstone conglomerate reservoir includes: clustering analysis of the reservoir using gamma and density electrical curves to establish a physical property-lithology identification chart; determining the identification criteria of the water flow dominant channel according to the physical property-lithology identification chart; wherein the identification criteria of the water flow dominant channel include: gamma>57API; density<2.33g / cm 3 ; Permeability>190mD; Porosity>16%. Gamma and density electrical curves are the most sensitive electrical responses to physical properties. Through the above electrical curves, an accurate physical property-lithology identification chart can be established to determine the four identification criteria for dominant water flow channels. According to the above identification criteria, the dominant water flow channels in the oil reservoir can be accurately determined, thus achieving accurate identification of the dominant water flow channels in the oil reservoir.

[0039] Specifically, the formation of water flow advantage channels is mainly controlled by two factors: internal and external. The internal factor is the heterogeneity of the reservoir, that is, the plane and vertical heterogeneity. The high permeability sand body strips are more likely to form seepage advantage channels; the external factor is the impact of long-term water injection production, which aggravates the formation of water flow advantage channels. Since the water injection development time of the well area is generally not long, the degree of reservoir scouring by the injected water is relatively low. Therefore, the formation of water flow advantage channels is mainly due to geological factors, including: (1) lithology: large-grained underwater diversion channels and braided dam dominant phases, and the bottom of the positive rhythm reservoir; (2) heterogeneity: the vertical and horizontal heterogeneity of the formation makes it easy for the injected water to advance along the high permeability zone to form secondary water flow advantage channels; (3) reservoir physical properties: the larger the porosity, the smaller the flow resistance of the water flow, and the easier it is to form water flow advantage channels. Water flow in water-driven oil reservoirs often bypasses low-permeability zones and takes high-permeability channels with less resistance. Therefore, the more permeable the zone, the more severe the scouring, and the easier it is to form a dominant water flow channel.

[0040] In this embodiment, the ultra-high permeability reservoir is a reservoir with a permeability greater than 500mD; the high permeability reservoir is a reservoir with a permeability between 500mD and 100mD; the medium permeability reservoir is a reservoir with a permeability between 100mD and 10mD; the low permeability reservoir is a reservoir with a permeability between 10mD and 1mD; and the ultra-low permeability reservoir is a reservoir with a permeability less than 1mD.

[0041] like Figures 2 to 4As shown in the figure, the gamma and density electrical curves were used to cluster the reservoirs, and then the dynamic data was used in combination with the heterogeneity characteristics of the reservoirs to form a lithology-physical property identification chart. Figure 2 For the plate about lithology, Figure 3 For the gamma and density chart, Figure 4 For the permeability and porosity chart. Figure 2 It can be seen that high permeability reservoirs are mainly concentrated in coarse sandstone and conglomerate. Figure 3 It can be seen that when gamma>57API and density<2.33g / cm 3 When the oil reservoir is a high permeability reservoir or an ultra-high permeability reservoir, it is very easy to form a dominant water flow channel. Figure 4 It can be seen that the lower limit of permeability of high permeability reservoir is 190md, and the porosity is greater than 16%.

[0042] In this embodiment, the identification method further includes: using the liquid production and absorption profile to determine the level of the dominant water flow channel.

[0043] In this embodiment, the level of the dominant water flow channel is determined by using the production and absorption profile, including: digitally processing the isotope logging tracer GR curve of the water absorption profile, and vertically grid-accurately dividing the development section of the oil reservoir; splitting the relative water absorption of each layer according to the amount of tracer GR, and calculating the relative water absorption of each layer in the vertical direction; and performing probability statistics based on the relative water absorption of each layer after splitting, and the inflection point is the dominant water flow channel of different levels.

[0044] Specifically, the vertical grid accuracy in this embodiment is 0.125m. Further, the relative water absorption of each layer = (relative water absorption of the water absorption section ÷ total amount of tracer GR of the water absorption section) * tracer GR amount of each layer, thus obtaining the relative water absorption of each layer with a thickness of 0.125 meters in the vertical direction.

[0045] The mathematical method of studying the statistical laws of random phenomena in nature is called probability statistics, also known as mathematical statistics. Based on its advantage of analyzing the distribution laws of messy data, probability statistics are performed on each layer of the oil reservoir divided by relative water absorption.

[0046] In this embodiment, the levels of water flow dominant channels include first-level dominant channels, second-level dominant channels, and third-level dominant channels. Figure 5 As shown, the relative water absorption of the first-level dominant channel accounts for more than 4%; the relative water absorption of the second-level dominant channel accounts for more than or equal to 2% and less than or equal to 4%; the relative water absorption of the third-level dominant channel accounts for less than 2%.

[0047] In this embodiment, determining the level of the dominant water flow channel using the production and absorption liquid profile also includes: analyzing the heterogeneity characteristics of the oil reservoir. Specifically, according to the porosity and permeability curves of each water absorption section, the permeability, permeability difference, permeability variation coefficient and permeability breakthrough coefficient of each point are calculated.

[0048] Table 1 Statistics of oil reservoir heterogeneity

[0049] Water flow advantage channel level Permeability mD Permeability difference Permeability coefficient of variation Permeability breakthrough coefficient First level advantage channel >500 >7 >0.7 >4 Second level advantage channel 500～100 3～7 0.3～0.7 2～4 Second level advantage channel 100～10 <3 <0.3 <2

[0050] As can be seen from Table 1, in this embodiment, through the relative water absorption-permeability intersection analysis, it can be determined that the permeability of the first-level dominant channel is greater than 500mD; the permeability of the second-level dominant channel is greater than 100mD and less than or equal to 500mD; the permeability of the third-level dominant channel is greater than 10mD and less than or equal to 100mD.

[0051] As can be seen from Table 1, in this embodiment, the permeability difference of the first-level dominant channel is greater than 7, the permeability variation coefficient is greater than 0.7, and the permeability sudden coefficient is greater than 4; the permeability difference of the second-level dominant channel is greater than or equal to 3 and less than or equal to 7, the permeability variation coefficient is greater than or equal to 0.3 and less than or equal to 0.7, and the permeability sudden coefficient is greater than or equal to 2 and less than or equal to 4; the permeability difference of the third-level dominant channel is less than 3, the permeability variation coefficient is less than 0.3, and the permeability sudden coefficient is greater than 4. In other words, the lower limit of the physical properties of the development of water flow dominant channels in sandy conglomerate reservoirs is permeability difference>7, permeability variation coefficient>0.7, and permeability sudden coefficient>4.

[0052] In this embodiment, the identification method further includes: calculating the correlation between the water injection volume of the water injection well and the liquid production volume of the oil production well by using the grey correlation coefficient, the inter-well seepage resistance and the rank correlation coefficient, and determining the volume of the dominant water flow channel.

[0053] Specifically, there will be a certain dynamic response between the injection and production well groups with developed dominant channels, and the injection and production data will show a certain correlation in the horizontal direction. The reservoir method can be used to calculate the data correlation between water injection and liquid production (water content) to determine the strength of the well group connectivity and the degree of development of the dominant channel. Therefore, the three-parameter calculation method is used to calculate the correlation between the water injection volume of the water injection well and the liquid production volume of the oil production well, so as to determine the volume of the dominant water flow channel, and further by comparing with the dynamic data, the inter-well connectivity can be determined.

[0054] In this embodiment, the calculation formula of the grey relational coefficient is:

[0055]

[0056] in, is the monthly injection volume sequence of the central injection well; is the monthly liquid production sequence of the surrounding effective oil-producing wells; k is the monthly data sequence number, i is the oil-producing well sequence number; ξ i (k) is the correlation coefficient between the water well in the kth month and the i-th oil producing well; ρ is the resolution factor.

[0057] In this embodiment, the resolution factor p is 0.5.

[0058] The application of the grey correlation coefficient analysis method in the identification of dominant channels is through the correspondence between the monthly water injection volume and the monthly liquid production volume. The description of this relationship requires numerical quantification. The correlation coefficient method is a method for quantifying the degree of correlation of various factors in the grey theory analysis system. It replaces the continuous concept with a discrete data column and judges the degree of correlation based on the similarity between the curves. The larger the correlation value, the greater the impact of the water injection well on the oil production well.

[0059] In this embodiment, the calculation formula of the interwell seepage resistance is:

[0060]

[0061] R oi =1 / (K oi h oi );

[0062] R wi =1 / (K wi h wi );

[0063] Among them, R t is the inter-well seepage resistance; N is the number of connected layers; i is the serial number of the connected layer; K oi is the permeability of the oil producing well at the i-th connected layer; h oi is the thickness of the i-th connected layer; K wi is the permeability of the injection well at the i-th connected layer; h wi is the thickness of the injection well at the i-th connected layer; R oi is the resistance of the oil producing well at the i-th connected layer; R wi is the resistance of the injection well at the i-th connected layer.

[0064] Specifically, the better the connectivity between oil and water wells, the greater the water flow along that direction. After long-term water flow scouring, it is easy to form a dominant direction of water flow. According to the principle of similarity between fluid seepage and electric current, the connectivity relationship between oil and water wells can be regarded as a parallel circuit, such as Figure 6 The larger the value of inter-well seepage resistance, the better the inter-well connectivity.

[0065] Furthermore, the production dynamics of oil wells in water injection reservoir development are mainly affected by the water drive conditions of the corresponding water injection wells. The size of the rank correlation coefficient between oil and water wells reflects the strength of the interaction between the wells. By calculating the rank correlation coefficient between the water injection volume and the oil and water production in a certain period of time, the relationship between the injection and production wells and the direction of oil and water movement can be determined, that is, which direction between the oil and water wells is to increase injection and increase oil, which direction is to increase injection and increase water (indicating that a channel has been formed underground), and which direction is to increase both oil and water, thereby providing a basis for adjusting the injection-production relationship and changing the direction of liquid flow. For a certain oil-producing well, the one with a larger correlation coefficient with the surrounding water injection wells is the main water inflow direction, and the one with a smaller correlation coefficient is the secondary water inflow direction.

[0066] In this embodiment, the rank correlation coefficient is the Spearman rank correlation coefficient. The calculation formula of the rank correlation coefficient is:

[0067]

[0068] d i =x i -y i ;

[0069] Among them, r s is the rank correlation coefficient; n is the number of samples; i is the sample number; x i is the monthly water injection volume of the injection well; i It is the monthly liquid production of surrounding effective oil producing wells.

[0070] In this embodiment, by accurately identifying the dominant water flow channel of the oil reservoir, the injection and production control strategy is adjusted accordingly according to the identification result, so as to improve the control degree of water drive reserves and the utilization degree of water drive reserves, reduce the natural decline rate of the oil reservoir, effectively control the water cut increase rate, improve the water drive development effect, and achieve the purpose of increasing the recovery rate.

[0071] From the above description, it can be seen that the above embodiments of the present invention achieve the following technical effects: the method for identifying the dominant water flow channel in the sandstone conglomerate reservoir includes: clustering analysis of the reservoir reservoir using gamma and density electrical curves to establish a physical property-lithology identification chart; determining the identification criteria of the dominant water flow channel according to the physical property-lithology identification chart; wherein the identification criteria of the dominant water flow channel include: gamma>57API; density<2.33g / cm 3 ; Permeability>190mD; Porosity>16%. Gamma and density electrical curves are the most sensitive electrical responses to physical properties. Through the above electrical curves, an accurate physical property-lithology identification chart can be established to determine the four identification criteria for dominant water flow channels. According to the above identification criteria, the dominant water flow channels in the oil reservoir can be accurately determined, thus achieving accurate identification of the dominant water flow channels in the oil reservoir.

[0072] It should be noted that the terms used herein are only for describing specific embodiments and are not intended to limit the exemplary embodiments according to the present application. As used herein, unless the context clearly indicates otherwise, the singular form is also intended to include the plural form. In addition, it should be understood that when the terms "comprise" and / or "include" are used in this specification, it indicates the presence of features, steps, operations, devices, components and / or combinations thereof.

[0073] It should be noted that the terms "first", "second", etc. in the specification and claims of the present application and the above-mentioned drawings are used to distinguish similar objects, and are not necessarily used to describe a specific order or sequence. It should be understood that the numbers used in this way can be interchanged where appropriate, so that the embodiments of the present application described herein can be implemented in an order other than those illustrated or described herein.

[0074] The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. For those skilled in the art, the present invention may have various modifications and variations. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present invention shall be included in the protection scope of the present invention.

Claims

1. A method for identifying dominant water flow channels in a sandstone conglomerate reservoir, characterized in that: include: Cluster analysis of oil reservoirs is performed using gamma and density electrical curves to establish a physical property-lithology identification chart; Determine the identification criteria of the dominant water flow channel according to the physical property-lithology identification plate; The identification criteria of the water flow dominant channel include: gamma > 57 API; density < 2.33 g / cm 3 ; Permeability>190mD; Porosity>16%.

2. The method for identifying the dominant water flow channel in a conglomerate reservoir according to claim 1, characterized in that: The identification method further comprises: The level of the dominant water flow channel is determined using the liquid production and absorption profile.

3. The method for identifying the dominant water flow channel in a conglomerate reservoir according to claim 2, characterized in that: The method of determining the level of the water flow dominant channel by using the liquid production and absorption profile includes: Digitally process the isotope logging tracer GR curve of the water absorption profile, and divide the development section of the oil reservoir into vertical grids with high precision; The relative water absorption of each layer is split according to the amount of tracer GR, and the relative water absorption of each layer in the vertical direction is calculated; According to the probability statistics of the relative water absorption of each layer after splitting, the inflection point is the dominant water flow channel of different levels.

4. The method for identifying the dominant water flow channel in a conglomerate reservoir according to claim 3, characterized in that: The levels of the water flow dominant channel include the first level dominant channel, the second level dominant channel and the third level dominant channel, wherein the relative water absorption of the first level dominant channel accounts for more than 4%; The relative water absorption ratio of the second-level dominant channel is greater than or equal to 2% and less than or equal to 4%; The relative water absorption of the third-level dominant channel accounts for less than 2%.

5. The method for identifying the dominant water flow channel in a sandy conglomerate reservoir according to claim 4, characterized in that: The permeability of the first-level dominant channel is greater than 500 mD; The permeability of the second-level dominant channel is greater than 100 mD and less than or equal to 500 mD; The permeability of the third-level dominant channel is greater than 10 mD and less than or equal to 100 mD.

6. The method for identifying the dominant water flow channel in a sandy conglomerate reservoir according to claim 5, characterized in that: The permeability difference of the first-level dominant channel is greater than 7, the permeability variation coefficient is greater than 0.7, and the permeability breakthrough coefficient is greater than 4; The permeability difference of the second-level dominant channel is greater than or equal to 3 and less than or equal to 7, the permeability variation coefficient is greater than or equal to 0.3 and less than or equal to 0.7, and the permeability breakthrough coefficient is greater than or equal to 2 and less than or equal to 4; The permeability difference of the third-level dominant channel is less than 3, the permeability variation coefficient is less than 0.3, and the permeability breakthrough coefficient is greater than 4.

7. The method for identifying dominant water flow channels in a conglomerate reservoir according to claim 1, characterized in that: The identification method further comprises: The grey correlation coefficient, inter-well seepage resistance and rank correlation coefficient are used to calculate the correlation between the water injection volume of the water injection well and the liquid production volume of the oil production well, and the volume of the dominant water flow channel is determined.

8. The method for identifying the dominant water flow channel in a conglomerate reservoir according to claim 7, characterized in that: The calculation formula of the grey correlation coefficient is: in, is the monthly injection volume sequence of the central injection well; is the monthly liquid production sequence of the surrounding effective oil-producing wells; k is the monthly data sequence number, i is the oil-producing well sequence number; ξ i (k) is the correlation coefficient between the water well in the kth month and the i-th oil producing well; ρ is the resolution factor.

9. The method for identifying the dominant water flow channel in a conglomerate reservoir according to claim 7, characterized in that: The calculation formula of the interwell seepage resistance is: R oi =1 / (K oi h oi ); R wi =1 / (K wi h wi ); Among them, R t is the inter-well seepage resistance; N is the number of connected layers; i is the serial number of the connected layer; K oi is the permeability of the oil producing well at the i-th connected layer; h oi is the thickness of the i-th connected layer; K wi is the permeability of the injection well at the i-th connected layer; h wi is the thickness of the injection well at the i-th connected layer; R oi is the resistance of the oil producing well at the i-th connected layer; R wi is the resistance of the injection well at the i-th connected layer.

10. The method for identifying dominant water flow channels in a conglomerate reservoir according to claim 7, characterized in that: The calculation formula of the rank correlation coefficient is: d i =x i -y i ; Among them, r s is the rank correlation coefficient; n is the number of samples; i is the sample number; x i is the monthly water injection volume of the injection well; i It is the monthly liquid production of surrounding effective oil producing wells.

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