Method, device and equipment for determining oil-water interface of fracture-vug type reservoir and storage medium

Abstract

The application discloses a method, device and equipment for determining an oil-water interface of a fractured-vug type reservoir and a storage medium, and the method comprises the following steps: acquiring an oil well basic characteristic parameter value of a to-be-measured reservoir unit system, and an initial water phase speed value and an initial water phase pressure value in an initial time period at intervals of a preset time length; based on a preset speed field iteration model, the initial water phase speed value and the initial water phase pressure value are solved according to the oil well basic characteristic parameter value, so as to obtain a water phase speed value of a time period after the initial time period; and based on the oil well basic characteristic parameter value and the water phase speed value of each time period, a preset interface solving model is used to obtain an oil-water interface value of each time period. By using the application, the dynamic change of the oil-water interface can be predicted, and the obtained oil-water interface value is time-effective and high in accuracy.

Description

Technical Field

[0001] This invention relates to the field of reservoir development technology, and in particular to a method, apparatus, equipment, and storage medium for determining the oil-water interface in fractured-vuggy reservoirs. Background Technology

[0002] In an oil reservoir, the interface between oil and water is called the oil-water interface. Taking carbonate fracture-vuggy reservoirs as a special example, their storage space mainly consists of fractures and caverns. During development, due to the gravity differentiation of oil and water (the rate of gravity differentiation varies between blocks, and even between caverns), the oil-water relationship in carbonate fracture-vuggy reservoirs is quite complex. Unlike traditional sandstone reservoirs, carbonate fracture-vuggy reservoirs do not have a uniform oil-water interface.

[0003] Due to the unique well-cavity relationship in carbonate fractured-vuggy reservoirs, the early stages of development are primarily waterless. However, once water is encountered, the water cut increases rapidly. Therefore, stabilizing oil production and controlling water flow becomes crucial to the success of developing carbonate fractured-vuggy reservoirs. Determining the location of water in an oil well has a significant impact on improving oil recovery. Accurately determining the location of water in an oil well requires identifying the oil-water interface, highlighting the vital importance of studying this interface for reservoir development.

[0004] Existing methods for determining the oil-water interface mainly include well logging, seismic methods, geochemical methods, and pressure methods. These methods are not well-suited for carbonate fractured-vuggy reservoirs and are primarily used to determine a fixed, static oil-water interface. However, in reservoir development, the oil-water interface can dynamically change as the opening and closing process progresses, as seen in carbonate fractured-vuggy reservoirs. Therefore, traditional methods struggle to accurately determine the oil-water interface. Summary of the Invention

[0005] The technical problem to be solved by the present invention is that the existing technology cannot obtain a dynamic oil-water interface, which leads to inaccurate determination of the oil-water interface and the water outlet location, thus making it impossible to take targeted water control and treatment measures, resulting in low crude oil recovery rate.

[0006] To address the aforementioned technical problems, this invention provides a method, apparatus, equipment, and storage medium for determining the oil-water interface in fractured-vuggy reservoirs.

[0007] A method for determining the oil-water interface in fractured-vuggy reservoirs includes:

[0008] Acquire the basic characteristic parameters of the oil wells in the reservoir unit system to be tested, as well as the initial water phase velocity and initial water phase pressure values ​​within an initial time period with a preset time interval.

[0009] Based on the preset velocity field iterative model, the water phase velocity value for the time period after the initial time period is obtained by solving the oil well basic characteristic parameter value, the initial water phase velocity value and the initial water phase pressure value.

[0010] Based on the basic characteristic parameters of the oil well and the water phase velocity values ​​for each time period, the oil-water interface values ​​for each time period are obtained using a preset interface calculation model.

[0011] In one embodiment, the reservoir unit system to be tested includes at least two oil wells; the acquisition of the basic characteristic parameter values ​​of the oil wells in the reservoir unit system to be tested, as well as the initial water phase velocity value and the initial water phase pressure value within an initial time period with a preset time interval, includes:

[0012] Based on the flow characteristics of the fractured-vuggy reservoir, a multidimensional physical model of the reservoir unit system to be tested is established;

[0013] The multidimensional physical model is reduced to a one-dimensional model.

[0014] The basic characteristic parameter values ​​of the oil well in the one-dimensional model, as well as the initial water phase velocity value and the initial water phase pressure value in the initial time period, are obtained to obtain the basic characteristic parameter values, initial water phase velocity value and initial water phase pressure value of the oil well in the reservoir unit system to be tested.

[0015] In one embodiment, the preset velocity field iterative model includes a velocity intermediate value calculation equation, a pressure value calculation equation set, and a velocity value calculation equation; the step of solving the water phase velocity value for the time period after the initial time period based on the preset velocity field iterative model, according to the oil well basic characteristic parameter value, the initial water phase velocity value, and the initial water phase pressure value, includes:

[0016] Substitute the oil well basic characteristic parameter value and the initial water phase velocity value into the velocity intermediate value calculation equation to calculate the water phase velocity intermediate value;

[0017] The water phase pressure value for the next time period is calculated based on the initial water phase pressure value and the pressure value equation set.

[0018] Substitute the intermediate value of the water phase velocity and the water phase pressure value of the next time period into the velocity value calculation equation to obtain the water phase velocity value of the next time period;

[0019] The water phase pressure value of the next time period is used as the new initial water phase pressure value, and the water phase velocity value of the next time period is used as the new initial water phase velocity value. The process of substituting the oil well basic characteristic parameter value and the initial water phase velocity value into the velocity intermediate value calculation equation to calculate the water phase velocity intermediate value is repeated until the water phase velocity values ​​of all time periods after the initial time period are obtained.

[0020] In one embodiment, the basic characteristic parameters of the oil well include the width of fractures, the cutoff area of ​​caverns, and the density and viscosity of the fluid in the reservoir unit system under test, wherein the fluid includes an oil phase and a water phase; the velocity intermediate value calculation equation includes:

[0021]

[0022] In the formula:

[0023]

[0024] The pressure value calculation equation set includes:

[0025]

[0026]

[0027] The velocity value calculation equation includes:

[0028]

[0029] Where v is the fluid velocity, p is the fluid pressure, n is the time period number, ρ is the fluid density, μ is the fluid viscosity, w is the width of the fracture in the reservoir unit system under test, Re represents the Reynolds number of the fracture, and A represents the cutoff area.

[0030] In one embodiment, the basic characteristic parameters of the oil well include the mobility of the water phase, the water-oil mobility ratio, the fracture-vuggy height of the reservoir unit system under test, the density of the oil phase, the density of the water phase, the pressure at height H of the reservoir unit system under test, and the bottom hole pressure.

[0031] The preset interface retrieval model includes:

[0032]

[0033] Among them, v w λ is the velocity value of the water phase. w ρ is the water phase mobility, M is the water-oil mobility ratio, H is the fracture-vuggy height of the reservoir unit system under test, and ρ is the water phase mobility. o ρ w The densities of the oil phase and the water phase are respectively, P H P0 is the pressure at height H of the reservoir unit system under test, P0 is the bottom hole pressure of the reservoir unit system under test, g is the acceleration due to gravity, and h is the pressure at height H. f This represents the oil-water interface value.

[0034] A device for determining the oil-water interface in a fractured-vuggy reservoir includes:

[0035] The information acquisition module is used to acquire the basic characteristic parameter values ​​of the oil wells of the reservoir unit system to be tested, as well as the initial water phase velocity value and the initial water phase pressure value within an initial time period with a preset time interval.

[0036] The water phase parameter calculation module is used to solve for the water phase velocity value of the time period after the initial time period based on the preset velocity field iterative model, according to the oil well basic characteristic parameter value, the initial water phase velocity value and the initial water phase pressure value.

[0037] The oil-water interface output module is used to obtain the oil-water interface value for each time period based on the basic characteristic parameter value of the oil well and the water phase velocity value for each time period using a preset interface calculation model.

[0038] In one embodiment, the reservoir unit system to be tested includes at least two oil wells; the information acquisition module includes:

[0039] The model building unit is used to build a multi-dimensional physical model of the reservoir unit system under test according to the flow conditions of the fractured-vuggy reservoir.

[0040] The model dimensionality reduction unit is used to reduce the dimensionality of the multidimensional physical model to obtain a one-dimensional model.

[0041] The information acquisition unit is used to acquire the basic characteristic parameter values ​​of the oil well in the one-dimensional model, as well as the initial water phase velocity value and the initial water phase pressure value in the initial time period, so as to obtain the basic characteristic parameter values, initial water phase velocity value and initial water phase pressure value of the oil well in the reservoir unit system to be tested.

[0042] In one embodiment, the preset velocity field iterative model includes a velocity intermediate value calculation equation, a pressure value calculation equation set, and a velocity value calculation equation; the water phase parameter calculation module includes:

[0043] The intermediate value calculation unit is used to substitute the oil well basic characteristic parameter value and the initial water phase velocity value into the velocity intermediate value calculation equation to calculate the water phase velocity intermediate value.

[0044] The pressure calculation unit is used to calculate the water phase pressure value for the next time period based on the initial water phase pressure value and the pressure equation set.

[0045] The velocity value calculation unit is used to substitute the intermediate value of the water phase velocity and the water phase pressure value of the next time period into the velocity value calculation equation to obtain the water phase velocity value of the next time period.

[0046] The iteration unit is used to take the water phase pressure value of the next time period as the new initial water phase pressure value and the water phase velocity value of the next time period as the new initial water phase velocity value, and repeat the functions of the intermediate value calculation unit, the pressure value calculation unit, and the velocity value calculation unit until the water phase velocity values ​​of all time periods after the initial time period are obtained.

[0047] A computer device includes a memory and a processor, the memory storing a computer program, and the processor executing the computer program performing the following steps:

[0048] Acquire the basic characteristic parameters of the oil wells in the reservoir unit system to be tested, as well as the initial water phase velocity and initial water phase pressure values ​​within an initial time period with a preset time interval.

[0049] Based on the preset velocity field iterative model, the water phase velocity value for the time period after the initial time period is obtained by solving the oil well basic characteristic parameter value, the initial water phase velocity value and the initial water phase pressure value.

[0050] Based on the basic characteristic parameters of the oil well and the water phase velocity values ​​for each time period, the oil-water interface values ​​for each time period are obtained using a preset interface calculation model.

[0051] A computer-readable storage medium having a computer program stored thereon, the computer program performing the following steps when executed by a processor:

[0052] Acquire the basic characteristic parameters of the oil wells in the reservoir unit system to be tested, as well as the initial water phase velocity and initial water phase pressure values ​​within an initial time period with a preset time interval.

[0053] Based on the preset velocity field iterative model, the water phase velocity value for the time period after the initial time period is obtained by solving the oil well basic characteristic parameter value, the initial water phase velocity value and the initial water phase pressure value.

[0054] Based on the basic characteristic parameters of the oil well and the water phase velocity values ​​for each time period, the oil-water interface values ​​for each time period are obtained using a preset interface calculation model.

[0055] Compared with the prior art, one or more embodiments of the above scheme may have the following advantages or beneficial effects: dividing the time after the initial time period into time steps and solving the oil-water interface value of each time step successively can predict the dynamic changes of the oil-water interface. The obtained oil-water interface value is timely and accurate, thus the accuracy of water inflow location determination is high, providing effective technical support for water inflow warning in oil wells, and facilitating targeted water control and treatment measures to improve crude oil recovery rate. Attached Figure Description

[0056] The scope of this disclosure can be better understood by reading the following detailed description of exemplary embodiments in conjunction with the accompanying drawings. The accompanying drawings are:

[0057] Figure 1 This is a flowchart illustrating a method for determining the oil-water interface in a fractured-vuggy reservoir in one embodiment.

[0058] Figure 2 This is a multi-dimensional physical model diagram from one embodiment;

[0059] Figure 3 for Figure 2 Simplified one-dimensional model diagram;

[0060] Figure 4 This is a flowchart illustrating the process of obtaining the water phase velocity value for a time period after the initial time period by solving a preset velocity field iterative model based on the oil well basic characteristic parameter values, the initial water phase velocity value, and the initial water phase pressure value.

[0061] Figure 5 This is a structural block diagram of a device for determining the oil-water interface of a slotted reservoir in one embodiment.

[0062] Figure 6 The oil phase velocity values ​​for the three well groups A1, A12, and A17 at different time steps;

[0063] Figure 7 The values ​​represent the water phase velocity at different time steps for the three well groups A1, A12, and A17. Detailed Implementation

[0064] To make the objectives, technical solutions, and advantages of the present invention clearer, the implementation method of the present invention will be described in detail below with reference to the accompanying drawings and embodiments, so that the process of how the present invention uses technical means to solve technical problems and achieve technical effects can be fully understood and implemented accordingly.

[0065] In existing technologies, the main methods for determining the oil-water interface in general oil reservoirs include well logging, seismic methods, geochemical methods, and pressure methods. The characteristics, advantages, and disadvantages of each method are shown in Table 1.

[0066] Table 1

[0067]

[0068]

[0069] As shown in Table 1, there are many methods for determining the oil-water interface, but for carbonate fracture-vuggy reservoirs, there are still some shortcomings, which can be summarized as follows:

[0070] 1. Carbonate fractured-vuggy reservoirs have well-developed fractures and vuggies, and their bedrock has low porosity and permeability, making them typical tight limestones with a high carbon-to-oxygen ratio. Logging methods in carbonate fractured-vuggy reservoirs have limitations, especially when wells encounter lost circulation, making logging operations impossible. Currently, a significant portion of production in carbonate fractured-vuggy reservoirs relies on new wells encountering vuggy zones; therefore, conventional logging methods cannot accurately detect the oil-water interface.

[0071] 2. Due to the unique nature of the reservoir space, carbonate fractured-vuggy reservoirs exhibit almost no capillary pressure. The flow between caverns and between dissolution pores is no longer the traditional seepage flow, but primarily pipe flow. Therefore, the traditional theories on capillary pressure determining the oil-water interface in sandstone reservoirs are difficult to apply to carbonate fractured-vuggy reservoirs.

[0072] 3. When installing pressure gauges to the bottom of the well in carbonate fractured-vuggy reservoirs, according to incomplete statistics, the encounter rate of caves in carbonate fractured-vuggy reservoirs is over 80%, making it difficult to stabilize the pressure gauges and affecting the accuracy of pressure testing. At the same time, actual development data show that carbonate fractured-vuggy reservoirs have edge water or bottom water, with strong water energy and complex oil-water relationships, making it difficult to obtain static pressure data of the oil layer and the oil-water interface.

[0073] It is evident that existing methods for determining the oil-water interface are not well-suited for carbonate fracture-vuggy reservoirs, and are primarily used to determine fixed, static oil-water interfaces. Therefore, this application provides a method for determining the oil-water interface in fracture-vuggy reservoirs, particularly carbonate fracture-vuggy reservoirs.

[0074] like Figure 1 As shown, in one embodiment, a method for determining the oil-water interface of a fractured-vuggy reservoir is provided, comprising the following steps:

[0075] S110: Obtain the basic characteristic parameter values ​​of the oil wells of the reservoir unit system to be tested, as well as the initial water phase velocity value and the initial water phase pressure value within the initial time period with a preset time interval.

[0076] The reservoir unit system to be tested refers to the reservoir where the oil-water interface needs to be determined. It can include a single well or multiple wells with mutual interference. For a single well, the basic characteristic parameter values ​​of that well are the basic characteristic parameter values ​​of the reservoir unit system to be tested. For multiple wells, they can be processed into one, and the basic characteristic parameter values ​​of that single well can be used as the basic characteristic parameter values ​​of the reservoir unit system to be tested. The preset duration and initial time period can be set according to actual needs.

[0077] S130: Based on the preset velocity field iterative model, the water phase velocity value is obtained by solving the oil well basic characteristic parameter value, initial water phase velocity value and initial water phase pressure value for the time period after the initial time period.

[0078] The velocity field iterative model is a pre-established model used to calculate velocity and pressure values. Specifically, the basic characteristic parameters of the oil well, the initial water phase velocity value, and the initial water phase pressure value can be input into the velocity field iterative model to obtain the water phase velocity and pressure values ​​for a time period after the initial time period. Then, the obtained water phase velocity and pressure values ​​can be input into the velocity field iterative model to obtain the water phase velocity and pressure values ​​for the next time period after this time period. This process is repeated to obtain the water phase velocity values ​​for multiple subsequent time periods.

[0079] S150: Based on the basic characteristic parameters of the oil well and the water phase velocity values ​​for each time period, the oil-water interface values ​​for each time period are obtained using a preset interface calculation model.

[0080] The interface determination model is a pre-established model used to determine the oil-water interface value. Specifically, by inputting the basic characteristic parameters of the oil well and the water phase velocity values ​​over a certain time period into the interface determination model, the oil-water interface value for that time period can be obtained. It can be understood that, to facilitate user access to information, after obtaining the oil-water interface value, it can be output to an information output device. For example, it can be output to a display screen for display, to a voice playback device for voice output, or to a user terminal connected via a network.

[0081] The above-mentioned method for determining the oil-water interface in fractured-vuggy reservoirs can be applied to any stage of fractured-vuggy reservoir development, especially to the development of carbonate fractured-vuggy reservoirs, whether they are old or new wells, and whether they are wells that have encountered water or not. By acquiring the basic characteristic parameters of the well in the reservoir unit system under test, as well as the initial parameters of the water phase (initial oil phase pressure and initial water phase pressure) within the initial time period, and solving the preset velocity field iterative model based on the initial parameters of the water phase, the water phase velocity values ​​for each time period after the initial time period are obtained. Then, based on the basic characteristic parameters of the well and the water phase velocity values ​​for each time period, the oil-water interface values ​​for the corresponding time period are obtained. In this way, the time after the initial time period is divided into time steps, and it is assumed that the reservoir unit system under test is in a steady state within each time step. By successively solving the oil-water interface values ​​for each time step, the dynamic changes of the oil-water interface can be predicted. The obtained oil-water interface values ​​are timely and accurate, thus ensuring a high accuracy in determining the water ingress location. This provides effective technical support for early warning of water ingress in oil wells, and facilitates targeted water control and treatment measures to improve oil recovery.

[0082] In one embodiment, the reservoir unit system to be tested includes at least two oil wells. Step S110 includes steps a1 to a3.

[0083] Step a1: Establish a multidimensional physical model of the reservoir unit system to be tested based on the flow conditions of the fractured-vuggy reservoir.

[0084] Specifically, reservoir flow conditions, such as location and direction, can be determined based on the presence of caverns and fractures in the oil well. For example... Figure 2 As shown, taking two oil wells as an example, a two-dimensional linear fracture-vuggy system model is established by equating the karst caves to rectangles and the fractures to lines. This model mainly consists of two interconnected karst cave units and six fracture units. From a fluid flow perspective, the model can be decomposed into two branch fluid flow channels and one main fluid flow channel. Specifically: the main fluid flow channel mainly includes one karst cave unit v1, fracture units f1, f4, and f5; the first branch fluid flow channel mainly includes fracture units f2 and f3; and the second branch fluid flow channel includes one karst cave unit v2 and fracture unit f6. The fluid inlet at the main fluid flow channel is fracture unit f5.

[0085] Step a2: Reduce the dimensionality of the multidimensional physical model to obtain a one-dimensional model.

[0086] In fracture-cavity units, cavities and fractures are interconnected, forming a network structure. Therefore, the flow direction of fluid differs between different fractures or cavities. In actual underground reservoirs, there is always a dominant fluid flow direction, i.e., flowing towards the wellbore. Other flow directions, like tributaries of a river, converge towards the dominant flow direction. Therefore, the multidimensional physical model can be simplified to a one-dimensional model. The principle of dimensionality reduction is: first, based on the fracture-cavity combination model, determine the dominant fluid flow channel and the dominant fluid flow direction; then, treat other fractures and cavities not in the dominant flow direction in parallel with those in the dominant flow direction; and calculate the cavities not in the dominant flow direction according to their actual flow direction. Figure 2 For example, the two-dimensional linear slot system model is simplified to a one-dimensional model, such as... Figure 3 As shown.

[0087] Step a3: Obtain the basic characteristic parameter values ​​of the oil well in the one-dimensional model, as well as the initial water phase velocity value and the initial water phase pressure value within the initial time period with a preset time interval, to obtain the basic characteristic parameter values, initial water phase velocity value and initial water phase pressure value of the oil well in the reservoir unit system to be tested.

[0088] By performing physical modeling and model simplification on a reservoir unit system comprising multiple wells, oil-water interface analysis of multi-well reservoirs can be performed. It is understood that in other embodiments, the reservoir unit system may consist of only one well.

[0089] Both the initial water phase velocity value and the initial water phase pressure value are dimensionless values. In one embodiment, step a3 includes: obtaining the basic characteristic parameter values ​​of the oil well in the one-dimensional model, and the water volume of the oil well in the one-dimensional model during an initial time period with a preset time interval; and converting the basic characteristic parameter values ​​and water volume to obtain the dimensionless initial water phase velocity value and the initial water volume and pressure value.

[0090] Specifically, a known method for converting production rate into velocity values ​​can be used to obtain dimensionless initial aqueous phase velocity values ​​based on basic characteristic parameter values ​​and water volume; a known method for converting production rate into pressure values ​​can be used to obtain dimensionless initial aqueous phase pressure values ​​based on basic characteristic parameter values ​​and water volume. Water volume reflects the production status of the oil well in the initial time period, and determining the initial parameters of the aqueous phase based on water volume is highly accurate. It is understood that in other embodiments, the initial parameters of the aqueous phase can also be obtained in other ways, such as manual input.

[0091] In one embodiment, such as Figure 4 As shown, the preset velocity field iterative model includes a velocity intermediate value calculation equation, a pressure value calculation equation set, and a velocity value calculation equation. Step S130 includes steps S131 to S137.

[0092] S131: Substitute the basic characteristic parameter value of the oil well and the initial water phase velocity value into the velocity intermediate value calculation equation to calculate the water phase velocity intermediate value.

[0093] S133: Calculate the water phase pressure value for the next time period based on the initial water phase pressure value and the pressure equation set.

[0094] S135: Substitute the intermediate value of the water phase velocity and the water phase pressure value of the next time period into the velocity value calculation equation to obtain the water phase velocity value of the next time period.

[0095] S137: Use the water phase pressure value of the next time period as the new initial water phase pressure value, use the water phase velocity value of the next time period as the new initial water phase velocity value, return to step S131, and repeat steps S131 to S137 until the water phase velocity values ​​of all time periods after the initial time period are obtained.

[0096] The number of time periods following the initial time period can be determined according to actual needs. By iteratively calculating the intermediate velocity value, pressure value, and velocity value, the water phase velocity values ​​for each time period following the initial time period can be accurately obtained.

[0097] In one embodiment, the basic characteristic parameters of the oil well include the width of fractures, the cutoff area of ​​caverns, and the density and viscosity of the fluid in the reservoir unit system under test; wherein the fluid includes an oil phase and a water phase. Specifically, the cutoff area can be calculated based on the length and width of the cavern.

[0098] The following research was conducted on the establishment of the velocity iteration model:

[0099] By combining the principle of mass balance and the continuity equation of fluid flow, a mathematical model of a single-slit hole, namely the NS equation, is established. Then, by combining the SOLA method and the projection method, and using an explicit step-by-step algorithm, the equation is solved to obtain the pressure and velocity values ​​at different time intervals.

[0100] Specifically, assuming the cave unit is rectangular with length and width a and b, the equivalent side length of the square is... Based on the continuity equation and the equation of motion of the fluid, the Navier-Stokes equations are established as follows:

[0101]

[0102] in,

[0103] v is the velocity of the fluid, p is the pressure of the fluid, ρ is the density of the fluid, μ is the viscosity of the fluid, w is the width of the fracture in the reservoir unit system under test, and Re represents the Reynolds number of the fracture.

[0104] Introducing an explicit step-by-step algorithm:

[0105]

[0106] Equation (2) is calculated in two steps, i.e., the pressure effect is ignored in the first step, and Equation (2) simplifies to:

[0107]

[0108] The pressure effect is corrected in the second step of the calculation:

[0109]

[0110] Combining the continuity equation:

[0111]

[0112] The pressure calculation formula is:

[0113]

[0114] Based on the above research and derivation, formula (3) is used as the equation for calculating the intermediate velocity value, formulas (5) and (6) are used as the equation set for calculating the pressure value, and formula (4) is used as the equation for calculating the velocity value to establish a velocity iteration model.

[0115] Specifically, the equation for calculating the intermediate velocity value includes:

[0116]

[0117] In the formula:

[0118]

[0119] Specifically, the equations for calculating the pressure value include:

[0120]

[0121]

[0122] Specifically, the equations for calculating the velocity value include:

[0123]

[0124] Where v is the fluid velocity, p is the fluid pressure, ρ is the fluid density, μ is the fluid viscosity, w is the fracture width in the reservoir unit system under test, Re represents the Reynolds number of the fracture, and A represents the cutoff area. n is the time period number; for example, n = 0 for the initial time period.

[0125] When the velocity field iterative model is used to obtain the water phase pressure and velocity values ​​in step 130, the fluid corresponds to the water phase, v is substituted with the water phase velocity value, ρ is substituted with the water phase density, p is substituted with the water phase pressure value, and μ is substituted with the water phase viscosity.

[0126] In one embodiment, the basic characteristic parameters of the oil well include the mobility of the water phase, the water-oil mobility ratio, the fracture-vuggy height of the reservoir unit system under test, the density of the oil phase, the density of the water phase, the pressure at height H of the reservoir unit system under test, and the bottom hole pressure.

[0127] The following research was conducted on the establishment of the interface retrieval model:

[0128] Considering the fluids in the karst cave system are oil and water, both viscous fluids, the velocity fields on the cross sections of the oil and water phases are different. However, when the fluid in the unfilled crevice tends towards steady-state flow, the rates of change of the oil phase, water phase, and the oil-water interface at the oil-water interface are the same. First, consider the flow equations and continuity equations under oil-water gravitational differentiation, which are as follows:

[0129]

[0130]

[0131] In the formula:

[0132] r is the radius of the unfilled cavity; v is the fluid velocity; ρ o ρ w ρ represents the density of the oil phase and the water phase, respectively; g is the acceleration due to gravity.

[0133] From equations (7) and (8), we can obtain:

[0134]

[0135] The general solution for pressure is: p = az + b, corresponding to the oil phase and water phase respectively:

[0136]

[0137] Where: h f p is the oil-water interface value. o p is the pressure value of the oil phase. w This represents the pressure value of the aqueous phase.

[0138] At the oil-water interface, the oil phase and water phase have equal pressure and velocity, that is:

[0139]

[0140] From equations (10) and (11), we can obtain:

[0141]

[0142] In the formula: M is the water-oil mobility ratio; H is the fracture-cavity height of the reservoir unit system to be tested.

[0143] At the oil-water interface, the rates of change of the oil phase, the water phase, and the oil-water interface are all the same, that is:

[0144]

[0145] In the formula: λ w v represents the mobility of the water phase. f This represents the rate of change at the oil-water interface.

[0146] The interface retrieval model is established using formula (13). Specifically, the preset interface retrieval model includes:

[0147]

[0148] Among them, v w λ is the velocity value of the water phase.w ρ is the mobility of the aqueous phase, M is the water-oil mobility ratio, H is the fracture-vuggy height of the reservoir unit system under test, and ρ is the water-oil mobility ratio. o ρ w The densities of the oil phase and the water phase are respectively, P H P0 is the pressure at height H of the reservoir unit system under test, P0 is the bottom hole pressure of the reservoir unit system under test, g is the acceleration due to gravity, and h is the pressure at height H. f This represents the oil-water interface value.

[0149] By using the above formula (13) to establish the interface acquisition model, and combining the water phase velocity values ​​obtained in steps S130 and S150 for each time period, the oil-water interface value in each time step is solved, thereby accurately obtaining the dynamic oil-water interface situation.

[0150] In one embodiment, such as Figure 5 As shown, a device for determining the oil-water interface in a fractured-vuggy reservoir is provided, including an information acquisition module 410, a water phase parameter calculation module 430, and an oil-water interface output module 450.

[0151] The information acquisition module 410 is used to acquire the basic characteristic parameter values ​​of the oil well of the reservoir unit system under test, as well as the initial water phase velocity value and the initial water phase pressure value within the initial time period with a preset time interval; the water phase parameter calculation module 430 is used to solve the water phase velocity value of the time period after the initial time period based on the preset velocity field iterative model, according to the basic characteristic parameter values ​​of the oil well, the initial water phase velocity value and the initial water phase pressure value; the oil-water interface output module 450 is used to obtain the oil-water interface value of each time period according to the basic characteristic parameter values ​​of the oil well and the water phase velocity value of each time period using a preset interface calculation model.

[0152] The aforementioned fractured-vuggy reservoir oil-water interface determination device acquires the basic characteristic parameters of the well in the reservoir unit system under test, as well as the initial parameters of the water phase (initial oil phase pressure and initial water phase pressure) within an initial time period. Based on the initial parameters of the water phase, it solves a preset velocity field iterative model to obtain the water phase velocity values ​​for each time period after the initial time period. Then, based on the basic characteristic parameters of the well and the water phase velocity values ​​for each time period, it obtains the corresponding oil-water interface value for that time period. In this way, by dividing the time after the initial time period into time steps, and assuming that the reservoir unit system under test is in a steady state within each time step, the oil-water interface value for each time step can be solved successively. This allows for the prediction of the dynamic changes of the oil-water interface. The obtained oil-water interface values ​​are timely and accurate, resulting in a high accuracy rate in determining the water ingress location. This provides effective technical support for early warning of water ingress in oil wells, and facilitates targeted water control and treatment measures to improve oil recovery.

[0153] In one embodiment, the reservoir unit system to be tested includes at least two oil wells. The information acquisition module 410 includes a model building unit (not shown), a model dimensionality reduction unit (not shown), and an information acquisition unit (not shown).

[0154] The model building unit is used to build a multi-dimensional physical model of the reservoir unit system under test according to the flow conditions of the fractured-vuggy reservoir; the model dimensionality reduction unit is used to reduce the multi-dimensional physical model to a one-dimensional model; the information acquisition unit is used to acquire the basic characteristic parameter values ​​of the oil well in the one-dimensional model, as well as the initial water phase velocity value and the initial water phase pressure value in the initial time period, so as to obtain the basic characteristic parameter values ​​of the oil well, the initial water phase velocity value and the initial water phase pressure value of the reservoir unit system under test.

[0155] By performing physical modeling and model simplification on a reservoir unit system comprising multiple wells, oil-water interface analysis of multi-well reservoirs can be performed. It is understood that in other embodiments, the reservoir unit system may consist of only one well.

[0156] In one embodiment, the information acquisition unit is used to acquire the basic characteristic parameter values ​​of the oil well in the one-dimensional model, as well as the water volume of the oil well in the one-dimensional model during an initial time period with preset intervals; and to obtain dimensionless initial water phase velocity values ​​and initial water volume pressure values ​​based on the basic characteristic parameter values ​​and water volume. The water volume reflects the production status of the oil well during the initial time period, and determining the initial parameters of the water phase based on the water volume is highly accurate.

[0157] In one embodiment, the preset velocity field iterative model includes a velocity intermediate value calculation equation, a pressure value calculation equation set, and a velocity value calculation equation; the water phase parameter calculation module 430 includes an intermediate value calculation unit (not shown), a pressure value calculation unit (not shown), a velocity value calculation unit (not shown), and an iteration unit (not shown).

[0158] The intermediate value calculation unit substitutes the basic characteristic parameters of the oil well and the initial water phase velocity value into the intermediate value velocity calculation equation to calculate the intermediate water phase velocity value. The pressure value calculation unit calculates the water phase pressure value for the next time period based on the initial water phase pressure value and the pressure value equation set. The velocity value calculation unit substitutes the intermediate water phase velocity value and the water phase pressure value for the next time period into the velocity value calculation equation to obtain the water phase velocity value for the next time period. The iteration unit uses the water phase pressure value for the next time period as the new initial water phase pressure value and the water phase velocity value for the next time period as the new initial water phase velocity value, repeating the functions of the intermediate value calculation unit, the pressure value calculation unit, and the velocity value calculation unit until the water phase velocity values ​​for all time periods after the initial time period are obtained.

[0159] By using iterative calculations of the velocity intermediate value calculation equation, the pressure value calculation equation set, and the velocity value calculation equation, the water phase velocity values ​​for each time period after the initial time period can be accurately obtained.

[0160] In one embodiment, the basic characteristic parameters of the oil well include the width of fractures, the cutoff area of ​​caverns, and the density and viscosity of fluids in the reservoir unit system under test.

[0161] Specifically, the equation for calculating the intermediate velocity value includes:

[0162]

[0163] In the formula:

[0164]

[0165] Specifically, the equations for calculating the pressure value include:

[0166]

[0167]

[0168] Specifically, the equations for calculating the velocity value include:

[0169]

[0170] Where v is the fluid velocity, p is the fluid pressure, ρ is the fluid density, μ is the fluid viscosity, w is the fracture width in the reservoir unit system under test, Re represents the Reynolds number of the fracture, and A represents the cutoff area. n is the sequence number of the time period.

[0171] In one embodiment, the basic characteristic parameters of the oil well include the mobility of the water phase, the water-oil mobility ratio, the fracture-vuggy height of the reservoir unit system under test, the density of the oil phase, the density of the water phase, the pressure at height H of the reservoir unit system under test, and the bottom hole pressure.

[0172] Specifically, the preset interface retrieval model includes:

[0173]

[0174] Among them, v w λ is the velocity value of the water phase. w ρ is the mobility of the aqueous phase, M is the water-oil mobility ratio, H is the fracture-vuggy height of the reservoir unit system under test, and ρ is the water-oil mobility ratio. o ρ w The densities of the oil phase and the water phase are respectively, P H P0 is the pressure at height H of the reservoir unit system under test, P0 is the bottom hole pressure of the reservoir unit system under test, g is the acceleration due to gravity, and h is the pressure at height H. f This represents the oil-water interface value.

[0175] Specific limitations regarding the device for determining the oil-water interface in fractured-vuggy reservoirs can be found in the limitations of the method for determining the oil-water interface in fractured-vuggy reservoirs described above, and will not be repeated here. Each module in the aforementioned device for determining the oil-water interface in fractured-vuggy reservoirs can be implemented entirely or partially through software, hardware, or a combination thereof. These modules can be embedded in or independent of the processor in a computer device in hardware form, or stored in the memory of a computer device in software form, so that the processor can call and execute the operations corresponding to each module. It should be noted that the module division in this embodiment is illustrative and only represents a logical functional division; other division methods may be used in actual implementation.

[0176] In one embodiment, a computer device is provided, including a memory and a processor, wherein the memory stores a computer program, and the processor executes the computer program to implement the steps in the above-described method embodiments.

[0177] The aforementioned computer equipment, which includes a processor capable of implementing the steps in the above method embodiments, can similarly solve the oil-water interface value at each time step and predict the dynamic changes of the oil-water interface. The obtained oil-water interface value is timely and highly accurate. Therefore, using this computer equipment can improve the crude oil recovery rate.

[0178] In one embodiment, a computer-readable storage medium is provided having a computer program stored thereon, which, when executed by a processor, implements the steps in the above method embodiments.

[0179] The aforementioned computer-readable storage medium, by employing a computer program capable of implementing the steps in the above method embodiments, can similarly solve for the oil-water interface value at each time step, predict the dynamic changes of the oil-water interface, and obtain the oil-water interface value with timeliness and high accuracy. Therefore, using this computer-readable storage medium can improve the crude oil recovery rate.

[0180] To better illustrate this application, the following description uses examples of its application:

[0181] Example 1

[0182] A certain well group A1 was selected, and the values ​​of basic characteristic parameters of the oil wells were collected. The results are shown in Table 2 below.

[0183] Table 2

[0184] Original saturation pressure (MPa) 58 Original reservoir pressure (MPa) 58 <![CDATA[Formation water density (g / cm 3 )]]> 1 <![CDATA[Crude oil density (g / cm 3 )]]> 0.87 Formation water viscosity (mPa.s) 0.51 Formation crude oil viscosity (mPa.s) 0.61 Oil phase kinetic energy correction factor 0.97 Water phase kinetic energy correction factor 1.02 Length of a karst cave unit (m) 15 Crack element length (m) 60 Equivalent diameter of a karst cave unit (m) 1.5 Equivalent diameter of crack element (m) 0.01 Permeability of filled karst caves (mD) 300 Crack permeability (mD) 1000

[0185] Starting from the start of production, the oil-water interface value is studied one year after production begins. The production time is one year, the time step (preset duration) is set to 30 days, and the calculation is iterated 10 times.

[0186] Step ①: Based on the oil phase production and formation pressure after 30 days of production, assign a dimensionless initial oil phase velocity value to A1, i.e.

[0187] Step ②: Substitute the initial oil phase velocity value obtained in step ① into the velocity intermediate value calculation equation, i.e., formula (3), to obtain the oil phase velocity intermediate value at this time step, i.e. Simultaneously, using the initial oil phase pressure value and the combined pressure equations, namely equations (5) and (6), the corresponding oil phase pressure value for the next time step is obtained, i.e.

[0188] Step ③: Substitute the intermediate oil phase velocity value obtained in the above steps and the oil phase pressure value corresponding to the next time step into the velocity value calculation equation, i.e., equation (4), to obtain the oil phase velocity value at the next time step, i.e. Substitute the oil phase velocity and oil phase pressure values ​​obtained in the above steps into equations (3), (5), (6) and (4) in turn, and then repeat the above steps to calculate the oil phase velocity values ​​at different time steps in turn.

[0189] Step 4: Similarly, the water phase velocity values ​​at different time steps can be obtained.

[0190] Step 5: Substitute the water phase velocity value into equation (13) to obtain the oil-water interface value at that time step, i.e., h. owc1 .

[0191] Example 2

[0192] A well group A12 was selected to collect numerical values ​​of basic characteristic parameters of the oil well. The oil-water interface value was studied one year after production commencement. The production period was one year, the time step (preset duration) was set to 30 days, and the calculation was iterated 10 times.

[0193] Step ①: Based on the oil phase production and formation pressure after 30 days of production, assign a dimensionless initial oil phase velocity value to A12, i.e.

[0194] Step ②: Substitute the initial oil phase velocity value obtained in step ① into the velocity intermediate value calculation equation, i.e., formula (3), to obtain the oil phase velocity intermediate value at this time step, i.e. Simultaneously, using the initial oil phase pressure value and the combined pressure equations, namely equations (5) and (6), the corresponding oil phase pressure value for the next time step is obtained, i.e.

[0195] Step ③: Substitute the intermediate oil phase velocity value obtained in the above steps and the oil phase pressure value corresponding to the next time step into the velocity value calculation equation, i.e., equation (4), to obtain the oil phase velocity value at the next time step, i.e. Substitute the oil phase velocity and oil phase pressure values ​​obtained in the above steps into equations (3), (5), (6) and (4) in turn, and then repeat the above steps to calculate the oil phase velocity values ​​at different time steps in turn.

[0196] Step 4: Similarly, the water phase velocity values ​​at different time steps can be obtained.

[0197] Step 5: Substitute the water phase velocity value into equation (13) to obtain the oil-water interface value at that time step, i.e., h. owc2 .

[0198] Example 3

[0199] A well group A17 was selected to collect numerical values ​​of basic characteristic parameters of the oil well. The oil-water interface value was studied one year after production commencement. The production period was one year, the time step (preset duration) was set to 30 days, and the calculation was iterated 10 times.

[0200] Step ①: Based on the oil phase production and formation pressure after 30 days of production, assign a dimensionless initial oil phase velocity value to A17, i.e.

[0201] Step ②: Substitute the initial oil phase velocity value obtained in step ① into the velocity intermediate value calculation equation, i.e., formula (3), to obtain the oil phase velocity intermediate value at this time step, i.e. Simultaneously, using the initial oil phase pressure value and the combined pressure equations, namely equations (5) and (6), the corresponding oil phase pressure value for the next time step is obtained, i.e.

[0202] Step ③: Substitute the intermediate oil phase velocity value obtained in the above steps and the oil phase pressure value corresponding to the next time step into the velocity value calculation equation, i.e., equation (4), to obtain the oil phase velocity value at the next time step, i.e. Substitute the oil phase velocity and oil phase pressure values ​​obtained in the above steps into equations (3), (5), (6) and (4) in turn, and then repeat the above steps to calculate the oil phase velocity values ​​at different time steps in turn.

[0203] Step 4: Similarly, the water phase velocity values ​​at different time steps can be obtained.

[0204] Step 5: Substitute the water phase velocity value into equation (13) to obtain the oil-water interface value at that time step, i.e., h. owc3 .

[0205] In the above embodiments one to three, the values ​​obtained according to steps ①, ②, ③ and ⑤ are as follows:

[0206]

[0207]

[0208]

[0209]

[0210]

[0211] Oil phase velocity values ​​at each time step are as follows Figure 6 As shown, the water phase velocity values ​​are as follows: Figure 7 As shown, the three values ​​at the same time step correspond to the values ​​of A1, A12, and A17 in that order.

[0212] The above steps can also be used to calculate other well groups, and the results are shown in Table 3 below.

[0213] Table 3

[0214] A1 5631.87 A10 5471.37 A2 5513.69 A11 5733.84 A3 5004.71 A12 5477.92 A4 5469.48 A13 5557.83 A5 5403.76 A14 5528.97 A6 5431.59 A15 5526.73 A7 5470.34 A16 5543.58 A8 5411.09 A17 5531.64 A9 5480.25 A18 5607.31

[0215] The comparison results with the actual measured oil-water interface values ​​of the same block are shown in Table 4.

[0216] Table 4

[0217] A1 5631.87 5519.23 2.04 A12 5477.92 5532.70 0.99 A17 5531.64 5476.32 1.01

[0218] As shown in Table 4, the relative error is controlled within 5%, which is within the allowable error range. This indicates that the method for determining the oil-water interface in fractured-vuggy reservoirs in this application can accurately obtain the oil-water interface value.

[0219] While the embodiments disclosed in this invention are as described above, the content is merely for the purpose of facilitating understanding of the invention and is not intended to limit the invention. Any person skilled in the art to which this invention pertains may make any modifications and changes in form and detail of the implementation without departing from the spirit and scope disclosed herein; however, the scope of protection of this invention shall still be determined by the scope defined in the appended claims.

Claims

1. A method for determining the oil-water interface in a fractured-vuggy reservoir, characterized in that, include: Acquire the basic characteristic parameters of the oil wells in the reservoir unit system to be tested, as well as the initial water phase velocity and initial water phase pressure values ​​within an initial time period with a preset time interval. Based on the preset velocity field iterative model, the water phase velocity value for the time period after the initial time period is obtained by solving the oil well basic characteristic parameter value, the initial water phase velocity value and the initial water phase pressure value. Based on the basic characteristic parameters of the oil well and the water phase velocity values ​​for each time period, the oil-water interface values ​​for each time period are obtained using a preset interface calculation model. The preset velocity field iterative model includes a velocity intermediate value calculation equation, a pressure value calculation equation set, and a velocity value calculation equation; based on the preset velocity field iterative model, the water phase velocity values ​​for the time period after the initial time period are obtained by solving the oil well basic characteristic parameter values, the initial water phase velocity values, and the initial water phase pressure values, including: Substitute the oil well basic characteristic parameter value and the initial water phase velocity value into the velocity intermediate value calculation equation to calculate the water phase velocity intermediate value. Based on the initial water phase pressure value and the pressure value calculation equation set, the water phase pressure value for the next time period is calculated. Substitute the median water phase velocity value and the water phase pressure value for the next time period into the velocity value calculation equation to obtain the water phase velocity value for the next time period; The water phase pressure value of the next time period is used as the new initial water phase pressure value, and the water phase velocity value of the next time period is used as the new initial water phase velocity value. The process of substituting the oil well basic characteristic parameter value and the initial water phase velocity value into the velocity intermediate value calculation equation to calculate the water phase velocity intermediate value is repeated until the water phase velocity values ​​of all time periods after the initial time period are obtained. The basic characteristic parameters of the oil well include the width of fractures, the cutoff area of ​​caverns, and the density and viscosity of the fluid in the reservoir unit system under test, wherein the fluid includes an oil phase and a water phase; the equation for calculating the intermediate velocity value includes: ； In the formula: ； The pressure value calculation equation set includes: ； ； The velocity value calculation equation includes: ； in, The velocity value of the fluid. Where n is the pressure value of the fluid, and n is the sequence number of the time period. For the density of the fluid, Let be the viscosity of the fluid, and w be the width of the fracture in the reservoir unit system under test. The Reynolds number of the crack is represented, and A represents the cutoff area.

2. The method according to claim 1, characterized in that, The reservoir unit system to be tested includes at least two oil wells; the acquisition of the basic characteristic parameter values ​​of the oil wells in the reservoir unit system to be tested, as well as the initial water phase velocity value and the initial water phase pressure value within an initial time period with a preset time interval, includes: Based on the flow characteristics of the fractured-vuggy reservoir, a multidimensional physical model of the reservoir unit system to be tested is established. The multidimensional physical model is reduced to a one-dimensional model. The basic characteristic parameter values ​​of the oil well in the one-dimensional model, as well as the initial water phase velocity value and the initial water phase pressure value in the initial time period, are obtained to obtain the basic characteristic parameter values, initial water phase velocity value and initial water phase pressure value of the oil well in the reservoir unit system to be tested.

3. The method according to claim 1, characterized in that, The basic characteristic parameters of the oil well include the mobility of the water phase, the water-oil mobility ratio, the fracture-vuggy height of the reservoir unit system under test, the density of the oil phase, the density of the water phase, and the height of the reservoir unit system under test. Pressure at the bottom of the well and pressure at the bottom of the well; The preset interface retrieval model includes: ； in, This represents the velocity value of the water phase. For the mobility of the water phase, The water-oil mobility ratio, The fracture height of the reservoir unit system under test is given. , These are the densities of the oil phase and the water phase, respectively. The height of the reservoir unit system to be tested Pressure at the location, The bottom hole pressure of the reservoir unit system to be tested is... It is the acceleration due to gravity. This represents the oil-water interface value.

4. A device for determining the oil-water interface in a fractured-vuggy reservoir, characterized in that, include: The information acquisition module is used to acquire the basic characteristic parameter values ​​of the oil wells of the reservoir unit system under test, as well as the initial water phase velocity value and the initial water phase pressure value within an initial time period with a preset time interval. The water phase parameter calculation module is used to solve for the water phase velocity value of the time period after the initial time period based on the preset velocity field iterative model, according to the oil well basic characteristic parameter value, the initial water phase velocity value and the initial water phase pressure value. The oil-water interface output module is used to obtain the oil-water interface value for each time period based on the basic characteristic parameter value of the oil well and the water phase velocity value for each time period using a preset interface calculation model. The preset velocity field iterative model includes a velocity intermediate value calculation equation, a pressure value calculation equation set, and a velocity value calculation equation; The aqueous phase parameter calculation module includes: The intermediate value calculation unit is used to substitute the oil well basic characteristic parameter value and the initial water phase velocity value into the velocity intermediate value calculation equation to calculate the water phase velocity intermediate value. The pressure value calculation unit is used to calculate the water phase pressure value for the next time period based on the initial water phase pressure value and the pressure value calculation equation set. The velocity value calculation unit is used to substitute the intermediate value of the water phase velocity and the water phase pressure value of the next time period into the velocity value calculation equation to obtain the water phase velocity value of the next time period. The iterative unit is used to take the water phase pressure value of the next time period as the new initial water phase pressure value and the water phase velocity value of the next time period as the new initial water phase velocity value, and repeat the functions of the intermediate value calculation unit, the pressure value calculation unit, and the velocity value calculation unit until the water phase velocity values ​​of all time periods after the initial time period are obtained. The basic characteristic parameters of the oil well include the width of fractures, the cutoff area of ​​caverns, and the density and viscosity of the fluid in the reservoir unit system under test, wherein the fluid includes an oil phase and a water phase; the equation for calculating the intermediate velocity value includes: ； In the formula: ； The pressure value calculation equation set includes: ； ； The velocity value calculation equation includes: ； in, The velocity value of the fluid. Where n is the pressure value of the fluid, and n is the sequence number of the time period. For the density of the fluid, Let be the viscosity of the fluid, and w be the width of the fracture in the reservoir unit system under test. The Reynolds number of the crack is represented, and A represents the cutoff area.

5. The apparatus according to claim 4, characterized in that, The reservoir unit system to be tested includes at least two oil wells; the information acquisition module includes: The model building unit is used to build a multi-dimensional physical model of the reservoir unit system under test according to the flow conditions of the fractured-vuggy reservoir. The model dimensionality reduction unit is used to reduce the dimensionality of the multidimensional physical model to obtain a one-dimensional model. The information acquisition unit is used to acquire the basic characteristic parameter values ​​of the oil well in the one-dimensional model, as well as the initial water phase velocity value and the initial water phase pressure value in the initial time period, so as to obtain the basic characteristic parameter values, initial water phase velocity value and initial water phase pressure value of the oil well in the reservoir unit system to be tested.

6. A computer device comprising a memory and a processor, wherein the memory stores a computer program, characterized in that, When the processor executes the computer program, it implements the steps of the method according to any one of claims 1 to 3.

7. A computer-readable storage medium having a computer program stored thereon, characterized in that, When the computer program is executed by a processor, it implements the steps of the method according to any one of claims 1 to 3.

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