Prediction method and device for steam cavity in steam drive and computer equipment

Abstract

The invention provides a prediction method and device for a steam cavity in steam flooding and computer equipment, and relates to the technical field of oil field oil extraction. The method comprises the steps that the incidence relation between wellhead production characteristics of a first production well and the bottom hole temperature is determined, and according to the incidence relation, the bottom hole temperature of a second production well is determined according to the wellhead production characteristics of the second production well; calculating the bottom hole pressure of the second production well; and comparing the well bottom temperature of the second production well with the well bottom temperature of the steam injection well, comparing the well bottom pressure of the second production well with the well bottom pressure of the steam injection well, and identifying a steam cavity at the well bottom of the second production well. According to the method, the incidence relation between the wellhead production characteristics and the bottom hole temperature is established by using the production data of the first production well with the bottom hole temperature monitoring data, and the bottom hole temperature of the second production well without the bottom hole temperature monitoring data is predicted by using the incidence relation. And rapid and accurate identification of the steam cavity of the second production well is realized.

Description

TECHNICAL FIELD

[0001] The present application belongs to the technical field of oil extraction, and particularly relates to a method for predicting a steam chamber in steam flooding, a device for predicting a steam chamber in steam flooding, a computer device and a machine-readable storage medium. BACKGROUND

[0002] Steam flooding is one of the most effective and mature methods in heavy oil development. Its recovery mechanism is that a large amount of heat energy in the injected steam heats the oil layer, thereby greatly reducing the viscosity of the crude oil, and the injected hot fluid drives the crude oil to the surrounding production wells for recovery, and the steam chamber continuously expands and occupies the volume of the crude oil. This technology began with the piston-type steam flooding reservoir model proposed by Marx-Langenheim in 1959. In 1964, a pilot test of 12 well groups was first carried out in Kern River Oilfield in the United States, which was successful, and the steam flooding recovery rate basically reached the theoretical calculation recovery rate. In 1991, the reverse nine-point steam flooding well group in Xinjiang Ke 6 and 9 blocks was successful after several failures in Du 163 block and Xinjiang Ke 9 block, in 1998, four well groups of steam flooding pilot test were implemented in QI 40 block of Liaohe Oilfield, and again successful, in 2003, seven well groups of steam flooding expansion test were carried out, in 2007, 138 well groups of steam flooding were implemented industrially, and good results were obtained. Its oil production rate is high, and the exploitation cost is low, and its technical advantages are recognized by oil industry people, and it is considered as one of the thermal recovery development technologies with the highest recovery rate.

[0003] However, steam flooding is affected by steam overlap and other factors in the exploitation process, and the development effect of steam flooding is poor. In order to improve the oil displacement efficiency of steam flooding and ensure the uniform advancement of the steam front and the uniform development of the steam chamber, accurate prediction of the steam chamber is very important. At present, the prediction methods for the steam chamber front mainly include numerical simulation, well temperature monitoring, microseismic monitoring, satellite remote sensing technology and mathematical models considering the pseudo-fluidity ratio, flow pressure difference and cumulative injection volume. Among them, the numerical simulation fitting process is time-consuming, the fitting precision is high, and the result often depends on the accuracy of the input parameters. The well temperature monitoring method needs to monitor many well points, has high frequency and high investment. The cost of microseismic monitoring is high, so it is limited to local well groups and cannot achieve full coverage. The mathematical model requires many parameters, and it is difficult to determine the values of the parameters.

[0004] In summary, the current prediction methods for the steam chamber have problems such as complicated process, untimely prediction, inaccurate prediction and the like. SUMMARY

[0005] The embodiment of the present application aims to provide a steam chamber prediction method in steam flooding, a steam chamber prediction device in steam flooding, a computer device and a machine readable storage medium, so as to overcome one or more defects of the steam chamber front prediction method based on numerical simulation, well temperature monitoring, microseismic monitoring, satellite remote sensing technology and mathematical model modeling in the prior art.

[0006] To achieve the above-mentioned purpose, the first aspect of the embodiment of the present application provides a steam chamber prediction method in steam flooding, comprising:

[0007] determining the correlation between the wellhead production characteristics and the bottomhole temperature of the first production well, and using the correlation to determine the bottomhole temperature of the second production well according to the wellhead production characteristics of the second production well;

[0008] calculating the bottomhole pressure of the second production well;

[0009] comparing the bottomhole temperature of the second production well with the bottomhole temperature of the steam injection well in the well group where the second production well is located, and comparing the bottomhole pressure of the second production well with the bottomhole pressure of the steam injection well, to identify the steam chamber at the bottomhole of the second production well;

[0010] The first production well is a production well with bottomhole temperature monitoring data, and the second production well is a production well without bottomhole temperature monitoring data.

[0011] In the embodiment of the present application, the determination of the correlation between the wellhead production characteristics and the bottomhole temperature of the first production well, and the use of the correlation to determine the bottomhole temperature of the second production well according to the wellhead production characteristics of the second production well, comprises:

[0012] establishing a relationship chart of the wellhead liquid production temperature, the wellhead liquid production rate and the bottomhole temperature of the first production well;

[0013] finding the bottomhole temperature of the second production well corresponding to the wellhead liquid production temperature and the wellhead liquid production rate of the second production well from the relationship chart.

[0014] In the embodiment of the present application, the establishment of the relationship chart of the wellhead liquid production temperature, the wellhead liquid production rate and the bottomhole temperature of the first production well comprises:

[0015] corresponding the wellhead liquid production temperature and the wellhead liquid production rate change data of the first production well recorded at different periods of time and the bottomhole temperature change data of the first production well monitored at different periods of time according to time, to obtain the combination of the wellhead liquid production temperature, the wellhead liquid production rate and the bottomhole temperature at the same period of time;

[0016] according to the preset interval into which the wellhead liquid production rate falls, classifying the combination of the wellhead liquid production temperature, the wellhead liquid production rate and the bottomhole temperature into the corresponding preset interval;

[0017] Curve fitting was performed on the wellhead production temperature and bottom hole temperature classified into each preset interval to obtain the relationship between the wellhead production temperature and bottom hole temperature in each preset interval.

[0018] Based on the aforementioned relationships, plot the relationship between wellhead production temperature and bottom hole temperature under different preset intervals;

[0019] The preset interval is a range divided according to the amount of fluid produced at the wellhead.

[0020] In a specific embodiment of the present invention, the step of comparing the bottom-hole temperature of the second production well with the bottom-hole temperature of the steam injection well in the well group where the second production well is located, and comparing the bottom-hole pressure of the second production well with the bottom-hole pressure of the steam injection well, to identify the steam chamber at the bottom of the second production well, includes:

[0021] Based on the bottom-hole temperature of the second production well, the bottom-hole temperature of the steam injection well in the well group where the second production well is located, the bottom-hole pressure of the second production well, and the bottom-hole pressure of the steam injection well, the temperature distribution map between the second production well and the steam injection well is determined by interpolation.

[0022] The temperature at the leading edge of the steam chamber is identified by utilizing the relationship between saturated steam pressure and temperature.

[0023] The spatial coordinates of the temperature at the leading edge of the steam chamber in the temperature distribution map are determined, and these spatial coordinates are used as the position coordinates of the leading edge of the steam chamber at the bottom of the second production well.

[0024] In a specific embodiment of the present invention, determining the temperature distribution map between the second production well and the steam injection well using interpolation based on the bottom-hole temperature of the second production well, the bottom-hole temperature of the steam injection well in the well group where the second production well is located, the bottom-hole pressure of the second production well, and the bottom-hole pressure of the steam injection well includes:

[0025] The distance between the second production well and the steam injection wells in the well group where the second production well is located is evenly divided into segments to obtain the spatial coordinates of each segment point;

[0026] Using the constraint that the temperature value at each segment point increases uniformly from the bottom temperature of the second production well to the bottom temperature of the steam injection well, interpolation is performed to obtain the temperature value at the spatial coordinates of each segment point other than the segment points where the second production well and the steam injection well are located, so that the absolute value of the temperature difference between any two adjacent segment points is equal.

[0027] A temperature distribution map between the second production well and the steam injection well is drawn based on the temperature values ​​of each segment point. The segment points where the second production well and the steam injection well are located are associated with the pressure values ​​at their own spatial coordinates.

[0028] In a specific embodiment of the present invention, the step of determining the temperature distribution map between the second production well and the steam injection well using interpolation based on the bottom-hole temperature of the second production well, the bottom-hole temperature of the steam injection well in the well group where the second production well is located, the bottom-hole pressure of the second production well, and the bottom-hole pressure of the steam injection well, further includes:

[0029] Using the constraint that the pressure value at each segment point increases uniformly from the bottom pressure of the second production well to the bottom pressure of the steam injection well, interpolation is used to obtain the pressure value at the spatial coordinates of each segment point other than the segment points where the second production well and the steam injection well are located, so that the absolute value of the pressure difference between any two adjacent segment points is equal.

[0030] Within the temperature distribution map, the temperature values ​​at the spatial coordinates of all segment points except those of the second production well and the steam injection well are correlated one-to-one with the pressure values ​​at the spatial coordinates of each segment point.

[0031] In a specific embodiment of the present invention, calculating the bottom hole pressure of the second production well includes:

[0032] The bottom pressure of the second production well was calculated based on the dynamic fluid level monitoring data of the second production well.

[0033] In a specific embodiment of the present invention, the step of calculating the bottom hole pressure of the second production well based on the dynamic fluid level monitoring data of the second production well includes:

[0034] Based on the oil layer depth of the second production well and the dynamic fluid level depth obtained from the dynamic fluid level monitoring data of the second production well, the bottom hole pressure of the second production well is calculated using Formula 1.

[0035] Formula 1 is: P = ρg(h1-h2), where P represents the bottom hole pressure of the second production well, ρ represents the formation fluid density, g represents the gravitational acceleration, h1 represents the depth of the oil layer, and h2 represents the depth of the dynamic fluid level.

[0036] In a specific embodiment of the present invention, there are multiple second production wells, and each second production well is located in the same well group. The method further includes:

[0037] Based on the position coordinates of the leading edge of the steam chamber of each second production well, draw a planar distribution diagram of the leading edge of the steam chamber of the well group where the second production well is located.

[0038] A second aspect of the present invention provides a predictive device for a steam chamber in a steam drive system, comprising:

[0039] The correlation determination module is used to determine the correlation between the wellhead production characteristics and the bottom hole temperature of the first production well, and to use this correlation to determine the bottom hole temperature of the second production well based on the wellhead production characteristics of the second production well.

[0040] The bottom hole pressure calculation module is used to calculate the bottom hole pressure of the second production well.

[0041] The steam chamber identification module is used to compare the bottom temperature of the second production well with the bottom temperature of the steam injection well in the well group where the second production well is located, and to compare the bottom pressure of the second production well with the bottom pressure of the steam injection well, so as to identify the steam chamber at the bottom of the second production well.

[0042] The first production well is a production well with bottom hole temperature monitoring data, and the second production well is a production well without bottom hole temperature monitoring data.

[0043] In a specific embodiment of the present invention, determining the correlation between the wellhead production characteristics and the bottom hole temperature of the first production well, and using this correlation to determine the bottom hole temperature of the second production well based on the wellhead production characteristics of the second production well, includes:

[0044] Establish a graph showing the relationship between the wellhead production temperature, wellhead production rate, and bottom hole temperature of the first production well.

[0045] Find the bottom temperature of the second production well corresponding to the wellhead production temperature and wellhead production volume of the second production well from the relationship diagram.

[0046] In a specific embodiment of the present invention, a relationship chart is established between the wellhead production temperature, the wellhead production rate, and the bottom hole temperature of the first production well, including:

[0047] By correlating the changes in wellhead production temperature and production volume of the first production well recorded at different times with the changes in bottom hole temperature of the first production well monitored at different times, a combination of wellhead production temperature, wellhead production volume and bottom hole temperature for the same period is obtained.

[0048] Based on the preset range into which the wellhead production falls, the combination of wellhead production temperature, wellhead production, and bottom hole temperature is categorized into the corresponding preset range.

[0049] Curve fitting was performed on the wellhead production temperature and bottom hole temperature classified into each preset interval to obtain the relationship between the wellhead production temperature and bottom hole temperature in each preset interval.

[0050] Based on the aforementioned relationships, plot the relationship between wellhead production temperature and bottom hole temperature under different preset intervals;

[0051] The preset interval is a range divided according to the amount of fluid produced at the wellhead.

[0052] In a specific embodiment of the present invention, the step of comparing the bottom-hole temperature of the second production well with the bottom-hole temperature of the steam injection well in the well group where the second production well is located, and comparing the bottom-hole pressure of the second production well with the bottom-hole pressure of the steam injection well, to identify the steam chamber at the bottom of the second production well, includes:

[0053] Based on the bottom-hole temperature of the second production well, the bottom-hole temperature of the steam injection well in the well group where the second production well is located, the bottom-hole pressure of the second production well, and the bottom-hole pressure of the steam injection well, the temperature distribution map between the second production well and the steam injection well is determined by interpolation.

[0054] The temperature at the leading edge of the steam chamber is identified by utilizing the relationship between saturated steam pressure and temperature.

[0055] The spatial coordinates of the temperature at the leading edge of the steam chamber in the temperature distribution map are determined, and these spatial coordinates are used as the position coordinates of the leading edge of the steam chamber at the bottom of the second production well.

[0056] In a specific embodiment of the present invention, determining the temperature distribution map between the second production well and the steam injection well using interpolation based on the bottom-hole temperature of the second production well, the bottom-hole temperature of the steam injection well in the well group where the second production well is located, the bottom-hole pressure of the second production well, and the bottom-hole pressure of the steam injection well includes:

[0057] The distance between the second production well and the steam injection wells in the well group where the second production well is located is evenly divided into segments to obtain the spatial coordinates of each segment point;

[0058] Using the constraint that the temperature value at each segment point increases uniformly from the bottom temperature of the second production well to the bottom temperature of the steam injection well, interpolation is performed to obtain the temperature value at the spatial coordinates of each segment point other than the segment points where the second production well and the steam injection well are located, so that the absolute value of the temperature difference between any two adjacent segment points is equal.

[0059] A temperature distribution map between the second production well and the steam injection well is drawn based on the temperature values ​​of each segment point. The segment points where the second production well and the steam injection well are located are associated with the pressure values ​​at their own spatial coordinates.

[0060] In a specific embodiment of the present invention, the step of determining the temperature distribution map between the second production well and the steam injection well using interpolation based on the bottom-hole temperature of the second production well, the bottom-hole temperature of the steam injection well in the well group where the second production well is located, the bottom-hole pressure of the second production well, and the bottom-hole pressure of the steam injection well, further includes:

[0061] Using the constraint that the pressure value at each segment point increases uniformly from the bottom pressure of the second production well to the bottom pressure of the steam injection well, interpolation is used to obtain the pressure value at the spatial coordinates of each segment point other than the segment points where the second production well and the steam injection well are located, so that the absolute value of the pressure difference between any two adjacent segment points is equal.

[0062] Within the temperature distribution map, the temperature values ​​at the spatial coordinates of all segment points except those of the second production well and the steam injection well are correlated one-to-one with the pressure values ​​at the spatial coordinates of each segment point.

[0063] In a specific embodiment of the present invention, calculating the bottom hole pressure of the second production well includes:

[0064] The bottom pressure of the second production well was calculated based on the dynamic fluid level monitoring data of the second production well.

[0065] In a specific embodiment of the present invention, the step of calculating the bottom hole pressure of the second production well based on the dynamic fluid level monitoring data of the second production well includes:

[0066] Based on the oil layer depth of the second production well and the dynamic fluid level depth obtained from the dynamic fluid level monitoring data of the second production well, the bottom hole pressure of the second production well is calculated using Formula 1.

[0067] Formula 1 is: P = ρg(h1-h2), where P represents the bottom hole pressure of the second production well, ρ represents the formation fluid density, g represents the gravitational acceleration, h1 represents the depth of the oil layer, and h2 represents the depth of the dynamic fluid level.

[0068] In a specific embodiment of the present invention, there are multiple second production wells, and each second production well is located in the same well group. The device further includes a distribution map drawing module, which is used to draw a planar distribution map of the steam chamber leading edge of the well group where the second production well is located based on the position coordinates of the leading edge of the steam chamber of each second production well.

[0069] A third aspect of the present invention provides a computer device including a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor executes the program to implement the method for predicting the steam chamber in a steam drive as described in the first aspect of the present invention.

[0070] A fourth aspect of the present invention provides a machine-readable storage medium having a computer program stored thereon, wherein the computer program, when executed by a processor, implements the method for predicting the steam chamber in a steam drive as described in the first aspect of the present invention.

[0071] In the above technical solution, a correlation is established between the wellhead production characteristics and the average bottom-hole temperature value of a production well (the first production well mentioned in the above technical solution) with bottom-hole temperature monitoring data. This correlation is then used to determine the bottom-hole temperature of the second production well to be identified for its steam cavity. After determining the bottom-hole temperature and pressure of the second production well and the injection wells in its well group, the steam cavity at the bottom of the second production well is identified based on the differences in bottom-hole temperature and pressure. Compared to numerical simulation-based steam cavity front prediction methods, this method eliminates the complex numerical simulation fitting process, thus reducing time consumption and lowering the computational power requirements of the execution terminal. Furthermore, the correlation between wellhead production characteristics and bottom-hole temperature can be extended from production wells with bottom-hole temperature monitoring data to multiple production wells without such data. Compared to steam cavity front prediction methods based on well temperature monitoring, this method eliminates the need for numerous wellpoint monitoring devices and high-frequency monitoring processes, thereby saving prediction costs. Compared to microseismic monitoring, it can achieve full coverage of well groups without requiring a large investment in monitoring equipment. Compared to mathematical modeling methods, it avoids the problem of poor prediction accuracy caused by numerous and difficult-to-determine parameters.

[0072] It is evident that the above technical solution enables rapid, accurate, and low-cost identification of the leading edge of the steam chamber between the second production well and the steam injection well in the well group.

[0073] Other features and advantages of the embodiments of the present invention will be described in detail in the following detailed description section. Attached Figure Description

[0074] The accompanying drawings are provided to further illustrate embodiments of the present invention and form part of the specification. They are used together with the following detailed description to explain the embodiments of the present invention, but do not constitute a limitation thereof. In the drawings:

[0075] Figure 1 The schematic diagram illustrates a flow chart of a method for predicting the steam chamber in a steam drive according to an embodiment of the present invention;

[0076] Figure 2 The schematic diagram illustrates a flow chart of another method for predicting the steam chamber in a steam drive according to an embodiment of the present invention;

[0077] Figure 3 The diagram illustrates the production curve of a single well.

[0078] Figure 4 The diagram illustrates the well temperature test curve;

[0079] Figure 5 A schematic diagram illustrating the relationship between wellhead production temperature and bottom hole temperature;

[0080] Figure 6 The diagram illustrates the production curve of production well A.

[0081] Figure 7 A schematic diagram illustrating the bottom hole temperature of production well A is shown.

[0082] Figure 8 The diagram schematically illustrates the temperature distribution between production well A and the steam injection well;

[0083] Figure 9 A schematic diagram illustrating the pressure relationship of saturated steam at different temperatures is provided.

[0084] Figure 10 The schematic diagram shows the position of the leading edge of the steam chamber between production well A and steam injection well;

[0085] Figure 11 The schematic diagram shows the planar distribution of the steam chamber leading edge of the well group where production well A is located;

[0086] Figure 12 The diagram schematically illustrates a structural block diagram of a steam chamber prediction device in a steam drive according to an embodiment of the present invention. Detailed Implementation

[0087] The specific embodiments of the present invention will be described in detail below with reference to the accompanying drawings. It should be understood that the specific embodiments described herein are for illustration and explanation only and are not intended to limit the scope of the present invention.

[0088] Example 1

[0089] Figure 1 This illustration schematically depicts a method for predicting the steam chamber in a steam-driven system according to an embodiment of the present invention. For example... Figure 1 As shown, the method for predicting the steam chamber in a steam drive provided by this embodiment of the invention may include the following steps:

[0090] Step S100: Determine the correlation between the wellhead production characteristics and bottom hole temperature of the first production well, and use this correlation to determine the bottom hole temperature of the second production well based on the wellhead production characteristics of the second production well. The first production well is a production well with bottom hole temperature monitoring data, and the second production well is a production well without bottom hole temperature monitoring data.

[0091] Step S102: Calculate the bottom hole pressure of the second production well.

[0092] In step S104, the bottom temperature of the second production well and the bottom temperature of the steam injection well in the well group where the second production well is located are compared with those obtained in step S100, and the bottom pressure of the second production well and the bottom pressure of the steam injection well in the well group where the second production well is located are compared with those obtained in step S102, so as to identify the steam chamber at the bottom of the second production well.

[0093] It is important to understand that wellhead production characteristics refer to various phenomena and characteristics that occur at the wellhead during oil reservoir development, typically including wellhead production temperature and wellhead production volume.

[0094] As in the above embodiment, for the second production well in the steam drive to be identified, there is no need to install temperature monitoring equipment at the bottom of the well. Instead, the bottom-hole temperature of the second production well is predicted by utilizing the correlation between the wellhead production characteristics and the bottom-hole temperature determined by the production data of the first production well, which has bottom-hole temperature monitoring data. In addition, to calculate the bottom-hole pressure, it is usually necessary to monitor the dynamic fluid level of the second production well. It can be seen that in the above technical solution, fewer monitoring devices are required to predict the steam cavity, making it a simple, convenient, and low-cost prediction solution.

[0095] In a comparative example, to determine the bottom hole temperature of the second production well, monitoring equipment for bottom hole temperature monitoring is installed at the bottom of the well, and monitoring equipment for wellhead produced fluid temperature monitoring is installed at the wellhead. Pumping parameters are adjusted at the surface to obtain production volume, water cut, and temperature data before and after adjustment. Based on these data, the input coefficient parameter in the initially established relationship between wellhead produced fluid temperature and bottom hole temperature is adjusted until the absolute difference between the bottom hole temperature values ​​before and after the adjustment is less than a first preset value. The final relationship between wellhead produced fluid temperature and bottom hole temperature is then determined based on this input coefficient, thereby determining the bottom hole temperature of the second production well. The input coefficient refers to the thermal conductivity between the produced fluid and the formation.

[0096] The comparative examples described above involve complex processes such as adjusting pumping parameters, monitoring the bottom temperature of the second production well, and iteratively adjusting the input coefficient. These processes are quite cumbersome and require a large number of monitoring devices. Therefore, the steam cavity prediction process implemented in this embodiment is simpler and more convenient. The correlation between the wellhead production characteristics and bottom temperature of the first production well can be extended to multiple production wells without bottom temperature monitoring data, rather than being limited to production wells requiring steam cavity identification.

[0097] It is known that bottomhole temperature affects multiple dimensions of characteristic parameters within the wellhead production characteristics. Through principal component analysis and expert experience, wellhead production temperature and wellhead production rate are identified as the main characteristic parameters affected by bottomhole temperature. Accordingly, in a specific embodiment of the present invention, the determined correlation between the wellhead production characteristics of the first production well and the bottomhole temperature refers to the correlation between wellhead production temperature, wellhead production rate, and bottomhole temperature. Specifically, step S100, determining the correlation between the wellhead production characteristics of the first production well and the bottomhole temperature, and using this correlation to determine the bottomhole temperature of the second production well based on the wellhead production characteristics of the second production well, includes the following steps:

[0098] S11, Establish a graph showing the relationship between the wellhead fluid production temperature, wellhead fluid production rate, and bottom hole temperature of the first production well;

[0099] S12, find the bottom temperature of the second production well corresponding to the wellhead production temperature and the wellhead production volume of the second production well from this relationship diagram.

[0100] The graph showing the relationship between the wellhead production temperature, production rate, and bottom hole temperature of the first production well refers to the graph showing the relationship between the wellhead production temperature and bottom hole temperature of the first production well under different wellhead production rates.

[0101] In some common embodiments, the multi-parameter relationship chart is usually obtained through mathematical statistics based on the specific values ​​of the multiple parameters. For example, after obtaining the wellhead production temperature, wellhead production rate, and bottom hole temperature from the wellhead production characteristics of the first production well, a relationship chart between the wellhead production temperature and bottom hole temperature of the first production well under different wellhead production rates can be established through regression fitting and other methods. Using regression fitting to establish a multi-parameter relationship chart has advantages such as high computational efficiency and high accuracy. This results in a highly accurate relationship chart between the wellhead production temperature, wellhead production rate, and bottom hole temperature of the first production well constructed using production data from the first production well with bottom hole temperature monitoring data. Furthermore, the construction process is efficient, thereby improving the accuracy and efficiency of steam chamber prediction.

[0102] For example, in a specific embodiment of the present invention, step S11, establishing a relationship chart between the wellhead production temperature, the wellhead production rate, and the bottom hole temperature of the first production well, specifically includes the following steps:

[0103] SS1 correlates the changes in wellhead production temperature and production volume of the first production well recorded at different times with the changes in bottom hole temperature of the first production well monitored at different times to obtain a combination of wellhead production temperature, wellhead production volume and bottom hole temperature for the same period.

[0104] SS2 categorizes the combination of wellhead production temperature, wellhead production rate, and bottom hole temperature into corresponding preset intervals based on the preset intervals into which the wellhead production rate falls. The preset intervals are defined based on the size of the wellhead production rate.

[0105] SS3 performs curve fitting on the wellhead production temperature and bottom hole temperature categorized into each preset interval, and obtains the relationship between the wellhead production temperature and bottom hole temperature in each preset interval.

[0106] SS4: Based on the various relationships obtained in step SS3, plot the relationship between wellhead production temperature and bottom hole temperature under different preset intervals.

[0107] In some common embodiments, bottom hole pressure is calculated using dynamic fluid level monitoring data. This embodiment of the invention can incorporate the calculation process from these common embodiments.

[0108] For example, in a specific embodiment of the present invention, step S102, calculating the bottom hole pressure of the second production well, specifically includes the following steps:

[0109] Based on the reservoir depth of the second production well and the dynamic fluid level depth obtained from the dynamic fluid level monitoring data of the second production well, the bottom hole pressure of the second production well is calculated using the following formula:

[0110] P = ρg(h1 - h2) (Formula 1);

[0111] In Formula 1 above, P represents the bottom hole pressure of the second production well, ρ represents the formation fluid density, g represents the gravitational acceleration, h1 represents the depth of the oil layer, and h2 represents the dynamic fluid level depth.

[0112] For example, in another specific embodiment of the present invention, step S102, calculating the bottom hole pressure of the second production well based on the dynamic fluid level monitoring data of the second production well, specifically includes the following steps:

[0113] Based on the wellhead pressure of the second production well and the dynamic fluid level depth obtained from the dynamic fluid level monitoring data of the second production well, the bottom hole pressure of the second production well is calculated using the following formula:

[0114] P = P0 + ρgh2 (Formula 2);

[0115] In Formula 2 above, P represents the bottom hole pressure of the second production well, ρ represents the formation fluid density, g represents the gravitational acceleration, P0 represents the wellhead pressure of the second production well, and h2 represents the dynamic fluid level depth.

[0116] For example, in a specific embodiment of the present invention, step S104, comparing the bottom-hole temperature of the second production well obtained in step S100 with the bottom-hole temperature of the steam injection well in the well group where the second production well is located, and comparing the bottom-hole pressure of the second production well obtained in step S102 with the bottom-hole pressure of the steam injection well in the well group where the second production well is located, to identify the steam chamber at the bottom of the second production well, specifically includes the following steps:

[0117] S41. Based on the bottom-hole temperature of the second production well, the bottom-hole temperature of the steam injection wells in the well group where the second production well is located, the bottom-hole pressure of the second production well, and the bottom-hole pressure of the steam injection wells in the well group where the second production well is located, the temperature distribution map between the second production well and the steam injection wells in the well group where the second production well is located is determined by interpolation.

[0118] S42, the temperature at the leading edge of the steam chamber is identified by the relationship between saturated steam pressure and temperature;

[0119] S43, determine the spatial coordinates of the temperature at the leading edge of the steam chamber in the temperature distribution map, and use these spatial coordinates as the position coordinates of the leading edge of the steam chamber at the bottom of the second production well.

[0120] As in the above embodiment, after determining the bottom-hole temperature and pressure of the second production well, an interpolation method is used to extrapolate the temperature distribution map (temperature field distribution map) between the second production well and the steam injection well. The temperature at the leading edge of the steam chamber is then identified using the relationship between saturated steam pressure and temperature. This allows the spatial coordinates of the steam chamber leading edge temperature to be found from the temperature distribution map, thus identifying the steam chamber. It is known that the steam chamber leading edge temperature is the critical value for the phase change of water vapor under the bottom-hole pressure of the second production well and the bottom-hole pressure of the steam injection well within the same well group as the second production well. This critical value can be confirmed through the relationship between saturated steam pressure and temperature. Therefore, as in the above embodiment, the entire steam chamber identification process uses the bottom-hole temperature and pressure of the second production well as input parameters. The types of input parameters are relatively few, and the computationally intensive process only involves interpolation calculations. The computational requirements on the execution terminal of the steam chamber prediction method are not high, and the overall steam chamber prediction process has high computational efficiency.

[0121] In the prior art, Chinese patent application CN202310189077.7 discloses a method for identifying the front of steam-driven thermal expansion in horizontal wells. The main process of this technical solution is as follows: A curve relating the integral of the flow pressure difference to the cumulative injection volume is fitted based on dynamic data of steam-driven production; the first-order numerical derivative of the integral curve is calculated; the integral curve and the first-order derivative curve are combined, and based on the quasi-steady-state seepage theory, the formation of a steam cavity in the reservoir is identified; after a steam cavity forms in the reservoir, the expansion radius of the steam cavity is calculated based on production data. In the above technical solution, the core technical point for identifying whether a steam cavity has formed in the reservoir is: plotting the integral curve and the first-order derivative curve on the same graph, with the cumulative injection volume as the horizontal axis, placing the integral of the flow pressure difference and the first-order derivative in a coordinate system, and combining the integral curve and the first-order derivative curve; when the integral curve and the first-order derivative curve completely coincide, a steam cavity has not formed in the reservoir. In the above embodiments of the present invention, it can be determined whether a steam cavity has been formed by comparing the bottom pressure of the second production well and the bottom temperature of the steam injection well. The premise of the determination is to obtain the accurate bottom temperature and bottom pressure of the second production well. This involves regression fitting between the wellhead production temperature and bottom temperature under different wellhead production rates when constructing the chart. It can be seen that the determination process is simpler and faster than the aforementioned prior art.

[0122] In existing technologies, the published paper titled "Research on Steam Drive Front Prediction Model Considering Quasi-Liveliness Ratio" studies a steam drive front prediction model when the quasi-liveliness ratio is 0, proposing that the injection parameters when the shape factor reaches its maximum value are the optimal parameters. However, in actual oil reservoirs, due to the high viscosity of crude oil in the formation or the low steam injection rate, the quasi-liveliness ratio is often large. In this case, optimizing the steam injection parameters using the maximum shape factor is limited. To address this situation, a steam drive front prediction model when the quasi-liveliness ratio is not 0 is studied using mathematical methods. After plotting the relationship between shape factor, quasi-liveliness ratio, steam injection rate, and front shape, it was found that increasing the steam injection rate can increase the shape factor, thereby reducing the quasi-liveliness ratio, mitigating steam overshoot, and improving the sweep efficiency of front drive. Since the steam injection rate is limited by the steam injection pressure, the coordination relationship between the steam injection rate and the steam injection pressure is studied. Using this relationship and the studied front model, the previous steam injection parameter optimization methods are improved. The modeling of the mathematical model and the construction of the relationship diagram of the four features involved in the published document are more complex and cumbersome in their identification process of the steam drive front than the above-mentioned embodiments of the present invention.

[0123] In existing technologies, a published paper titled "Study on the Morphology of the Steam Front in Shallow Extra-Heavy Oil Dredging and Discharge Combined Development" investigates the combined forces of dredging and discharge and the velocity of crude oil movement. Through analysis and derivation, it derives the equation for the morphology of the steam front, revealing key influencing factors, including the ratio of vertical to horizontal permeability, crude oil viscosity, steam injection rate, porosity, and oil saturation. Furthermore, it uses reservoir numerical simulation to obtain the development morphology, temperature field distribution, and remaining oil distribution of the steam front at different locations over different times. This published paper involves the construction of dynamic equations for the steam front and numerical simulation techniques, involving numerous parameters and complex calculations.

[0124] Based on the analysis of the prior art above, the above embodiments of the present invention involve fewer input parameters and a simpler calculation process, making the entire steam chamber prediction process more accurate and faster.

[0125] For example, in one specific embodiment of the present invention, the temperature at the leading edge of the steam chamber is identified using the relationship between saturated steam pressure and temperature, specifically including:

[0126] Find the critical temperature value of the water vapor phase change corresponding to the bottom pressure of the second production well from the pre-input saturated steam temperature and pressure relationship table or saturated steam temperature and pressure relationship curve, and take the critical temperature value as the steam chamber front temperature.

[0127] For example, in a specific embodiment of the present invention, step S41, based on the bottom-hole temperature of the second production well, the bottom-hole temperature of the steam injection wells in the well group where the second production well is located, the bottom-hole pressure of the second production well, and the bottom-hole pressure of the steam injection well, determines the temperature distribution map between the second production well and the steam injection wells in the well group where the second production well is located using an interpolation method, specifically including the following steps:

[0128] S410, the distance between the second production well and the steam injection well in the well group where the second production well is located is evenly divided into segments to obtain the spatial coordinates of each segment point;

[0129] S412, with the constraint that the temperature value at the spatial coordinates of each segment point increases uniformly from the bottom temperature of the second production well to the bottom temperature of the steam injection well, interpolation is used to obtain the temperature value at the spatial coordinates of each segment point other than the segment points where the second production well and the steam injection well are located, so that the absolute value of the temperature difference between any two adjacent segment points is equal.

[0130] S414. A temperature distribution map between the second production well and the steam injection well is drawn based on the temperature values ​​of each segment point. The segment points where the second production well and the steam injection well are located are associated with the pressure values ​​at their own spatial coordinates.

[0131] It should be understood that the interpolation method described in steps S410 to S414 is only a commonly used uniform interpolation method based on contour lines. Those skilled in the art can understand the applicability of other interpolation methods in this invention and provide one or more methods for constructing temperature distribution maps based on other interpolation methods. This embodiment will not elaborate on this part.

[0132] To facilitate observation of temperature and pressure changes between the second production well and the steam injection well, in one specific embodiment, the pressure values ​​at their own spatial coordinates are also associated with other segment points besides the segment points where the second production well and the steam injection well are located.

[0133] Accordingly, the following steps are included before step S414:

[0134] S413, with the pressure value at each segment point increasing uniformly from the bottom pressure of the second production well to the bottom pressure of the steam injection well in the well group where the second production well is located as the constraint, interpolation is used to obtain the pressure value at the spatial coordinates of each segment point other than the segment point where the second production well and the steam injection well are located, so that the absolute value of the pressure difference between any two adjacent segment points is equal.

[0135] Step S414 is followed by the following steps:

[0136] S415, within the temperature distribution map, the temperature values ​​at the spatial coordinates of each segment point, except for the segment point where the second production well and the steam injection well in the well group where the second production well are located, are correlated one-to-one with the pressure values ​​at the spatial coordinates of each segment point.

[0137] Example 2

[0138] Figure 2 The schematic diagram illustrates a flow chart of another method for predicting the steam chamber in a steam drive according to an embodiment of the present invention. Figure 2 As shown, the difference between the method for predicting the steam chamber in a steam-driven system provided in this embodiment and Embodiment 1 is that: there are multiple second production wells, and each second production well is located in the same well group; the method further includes the following steps after step S104:

[0139] Step S106: Draw a planar distribution map of the steam chamber leading edge of the well group where the second production well is located, based on the position coordinates of the leading edge of the steam chamber of each second production well.

[0140] Drawing a planar distribution map of the steam chamber front edge of the well group facilitates the intuitive identification of the steam chamber by surface personnel, provides a basis for the rational development and scientific management of steam-driven oilfields, and slows down the decline in block production.

[0141] Example 3

[0142] This embodiment is an application of the above embodiment two in a specific block, including the following implementation steps:

[0143] Step A1: Establish a graph showing the relationship between wellhead production temperature, wellhead production rate, and bottom hole temperature, specifically including:

[0144] 1) Select production wells in the Qi 40 Lianhua oil layer steam drive well group that are producing normally and have achieved effective displacement. Their single-well production curves are as follows: Figure 3 As shown;

[0145] 2) Monitoring wells with appropriate testing frequency and normal data were selected from the 40 Lianhua oil layer steam drive well group. Their single-well temperature test curves are shown below. Figure 4 As shown;

[0146] 3) Based on the downhole temperature test data of each well at different times and the production fluid output and temperature at the wellhead, the production fluid output was classified into three levels: 10–20 t / d, 20–30 t / d, and greater than 30 t / d. The relationship between the production fluid temperature at the wellhead and the bottomhole temperature test data under different production fluid outputs was then derived and plotted. The plot is shown below. Figure 5 As shown, the chart includes three straight lines: the yellow line represents the relationship between wellhead production temperature and bottom hole temperature at a wellhead production rate of 10–20 t / d; the blue line represents the relationship between wellhead production temperature and bottom hole temperature at a wellhead production rate of 20–30 t / d; and the green line represents the relationship between wellhead production temperature and bottom hole temperature at a wellhead production rate greater than 30 t / d.

[0147] It is important to understand that the average well temperature at different oil layer depths within each period is calculated from the bottom hole temperature test data of each period. This average value is then used in the regression process. Accordingly, the bottom hole temperature in the resulting chart represents the average well temperature at different oil layer depths.

[0148] Step A2: Calculate the bottom hole temperature of each production well in the well group that needs to be identified for steam chambers using the chart established in Step A1.

[0149] Taking production well A as an example, the current wellhead production rate of production well A is 27 t / d, and the wellhead production temperature is 61℃. Using the chart, the bottom hole temperature of production well A is calculated to be 139℃. The production curve of production well A is as follows: Figure 6 As shown in the diagram, this is a schematic diagram of using a chart to identify the bottom hole temperature of production well A. Figure 7 As shown.

[0150] Step A3: Calculate the bottom hole pressure of each production well in the well group that needs to be identified for steam chambers.

[0151] For example, if the current oil layer depth of production well A is 780m and the current dynamic fluid level depth is 580m, the bottom hole pressure of production well A is calculated to be 2.0MPa according to Formula 1.

[0152] Step A4: Use interpolation to determine the temperature distribution between each production well and the steam injection well within the well group that needs to be identified for steam chamber identification.

[0153] For example, in the well group containing production well A, the bottom-hole temperature of the steam injection well is 250℃ and the bottom-hole pressure is 2.5MPa. The bottom-hole temperature of production well A is 139℃ and the bottom-hole pressure is 2.0MPa. Dividing the distance from the steam injection well to production well A into 5 equal parts, the temperature and pressure values ​​at each segment point can be calculated, and a temperature distribution diagram can be drawn, such as... Figure 8 As shown.

[0154] Step A4: Determine the temperature at the leading edge of the steam chamber using the relationship between saturated steam pressure and temperature.

[0155] For example, for production well A, the bottom hole pressure of production well A is 2.0 MPa. Using a pre-inputted table of saturated steam pressure-temperature relationships (Table 1) and curves showing these relationships (…),… Figure 9 As can be seen, the steam chamber temperature corresponding to a pressure of 2 MPa is 212℃, and the pressure corresponding to 212℃ in the temperature distribution diagram is 2.33 MPa. (This information is obtained from Table 1 and...) Figure 9 It can be seen that the steam chamber temperature corresponding to a pressure of 2.33 MPa is 222℃, which is the steam chamber leading edge temperature Tq.

[0156] Table 1

[0157] Pressure, MPa Corresponding steam pocket temperature °C 2 212 2.1 216 2.2 219 2.3 221 2.4 223 2.5 225

[0158] Step A5: Determine the location of the leading edge of the steam chamber at the bottom of each production well within the well group that requires steam chamber identification. Specifically:

[0159] The position of the leading edge of the steam chamber is identified from the temperature distribution map and the temperature Tq at the leading edge of the steam chamber as determined in step A4.

[0160] For example, the well group for steam cavity identification belongs to a typical steam-driven reverse nine-point well network, with a well spacing of 70m between the production well and the injection well. The calculated distance L from the leading edge of the steam cavity of production well A to the injection well is 17.2m. The calculation process is as follows: Similarly, the distance from the steam chamber leading edge of other production wells in the same well group to the steam injection well can be calculated, as shown in Table 2 and... Figure 10 As shown.

[0161] Table 2

[0162]

[0163] Step A6: Based on the positions of the steam chamber leading edges at the bottom of each production well determined in Step A5, draw a planar distribution diagram of the steam chamber leading edges of the well group, as shown below. Figure 11 As shown.

[0164] After mapping the steam drive front distribution of the well groups, the steam drive process was guided, resulting in a significant improvement in oil recovery. According to recovery statistics, the recovery rate increased by 5% after applying the aforementioned steam chamber prediction method to guide the steam drive process in ordinary heavy oil in 125 well groups.

[0165] Example 4

[0166] Figure 12 This schematically illustrates a steam cavity prediction device 400 for steam drive according to an embodiment of the present invention, including a correlation determination module 410, a bottom hole pressure calculation module 420, and a steam cavity identification module 430, wherein:

[0167] The correlation determination module 410 is used to determine the correlation between the wellhead production characteristics of the first production well and the average bottom hole temperature, and to use the correlation to determine the bottom hole temperature of the second production well based on the wellhead production characteristics of the second production well.

[0168] Bottom hole pressure calculation module 420 is used to calculate the bottom hole pressure of the second production well;

[0169] The steam chamber identification module 430 is used to compare the bottom temperature of the second production well with the bottom temperature of the steam injection well in the well group where the second production well is located, and to compare the bottom pressure of the second production well with the bottom pressure of the steam injection well, so as to identify the steam chamber at the bottom of the second production well.

[0170] The first production well is a production well with bottom hole temperature monitoring data, while the second production well is a production well without bottom hole temperature monitoring data.

[0171] In a specific embodiment of the present invention, determining the correlation between the wellhead production characteristics of the first production well and the average bottom hole temperature, and using this correlation to determine the bottom hole temperature of the second production well based on the wellhead production characteristics of the second production well, includes:

[0172] Establish a graph showing the relationship between the wellhead production temperature, wellhead production rate, and bottom hole temperature of the first production well.

[0173] Find the bottom temperature of the second production well corresponding to the wellhead production temperature and wellhead production volume of the second production well from the relationship diagram.

[0174] In a specific embodiment of the present invention, establishing the relationship chart between the wellhead production temperature, the wellhead production rate, and the bottom hole temperature of the first production well includes:

[0175] By correlating the changes in wellhead production temperature and production volume of the first production well recorded at different times with the changes in bottom hole temperature of the first production well monitored at different times, a combination of wellhead production temperature, wellhead production volume and bottom hole temperature for the same period is obtained.

[0176] Based on the preset range into which the wellhead production falls, the combination of wellhead production temperature, wellhead production, and bottom hole temperature is categorized into the corresponding preset range.

[0177] Curve fitting was performed on the wellhead production temperature and bottom hole temperature classified into each preset interval to obtain the relationship between the wellhead production temperature and bottom hole temperature in each preset interval.

[0178] Based on the aforementioned relationships, plot the relationship between wellhead production temperature and bottom hole temperature under different preset intervals;

[0179] The preset interval is a range divided according to the amount of fluid produced at the wellhead.

[0180] In a specific embodiment of the present invention, the step of comparing the bottom-hole temperature of the second production well with the bottom-hole temperature of the steam injection well in the well group where the second production well is located, and comparing the bottom-hole pressure of the second production well with the bottom-hole pressure of the steam injection well, to identify the steam chamber at the bottom of the second production well, includes:

[0181] Based on the bottom-hole temperature of the second production well, the bottom-hole temperature of the steam injection well in the well group where the second production well is located, the bottom-hole pressure of the second production well, and the bottom-hole pressure of the steam injection well, the temperature distribution map between the second production well and the steam injection well is determined by interpolation.

[0182] The temperature at the leading edge of the steam chamber is identified by utilizing the relationship between saturated steam pressure and temperature.

[0183] The spatial coordinates of the temperature at the leading edge of the steam chamber in the temperature distribution map are determined, and these spatial coordinates are used as the position coordinates of the leading edge of the steam chamber at the bottom of the second production well.

[0184] In a specific embodiment of the present invention, determining the temperature distribution map between the second production well and the steam injection well using interpolation based on the bottom-hole temperature of the second production well, the bottom-hole temperature of the steam injection well in the well group where the second production well is located, the bottom-hole pressure of the second production well, and the bottom-hole pressure of the steam injection well includes:

[0185] The distance between the second production well and the steam injection wells in the well group where the second production well is located is evenly divided into segments to obtain the spatial coordinates of each segment point;

[0186] Using the constraint that the temperature value at each segment point increases uniformly from the bottom temperature of the second production well to the bottom temperature of the steam injection well, interpolation is performed to obtain the temperature value at the spatial coordinates of each segment point other than the segment points where the second production well and the steam injection well are located, so that the absolute value of the temperature difference between any two adjacent segment points is equal.

[0187] A temperature distribution map between the second production well and the steam injection well is drawn based on the temperature values ​​of each segment point. The segment points where the second production well and the steam injection well are located are associated with the pressure values ​​at their own spatial coordinates.

[0188] In a specific embodiment of the present invention, the step of determining the temperature distribution map between the second production well and the steam injection well using interpolation based on the bottom-hole temperature of the second production well, the bottom-hole temperature of the steam injection well in the well group where the second production well is located, the bottom-hole pressure of the second production well, and the bottom-hole pressure of the steam injection well, further includes:

[0189] Using the constraint that the pressure value at each segment point increases uniformly from the bottom pressure of the second production well to the bottom pressure of the steam injection well, interpolation is used to obtain the pressure value at the spatial coordinates of each segment point other than the segment points where the second production well and the steam injection well are located, so that the absolute value of the pressure difference between any two adjacent segment points is equal.

[0190] Within the temperature distribution map, the temperature values ​​at the spatial coordinates of all segment points except those of the second production well and the steam injection well are correlated one-to-one with the pressure values ​​at the spatial coordinates of each segment point.

[0191] In a specific embodiment of the present invention, calculating the bottom hole pressure of the second production well includes:

[0192] The bottom pressure of the second production well was calculated based on the dynamic fluid level monitoring data of the second production well.

[0193] In a specific embodiment of the present invention, the step of calculating the bottom hole pressure of the second production well based on the dynamic fluid level monitoring data of the second production well includes:

[0194] Based on the oil layer depth of the second production well and the dynamic fluid level depth obtained from the dynamic fluid level monitoring data of the second production well, the bottom hole pressure of the second production well is calculated using Formula 1.

[0195] Formula 1 is: P = ρg(h1-h2), where P represents the bottom hole pressure of the second production well, ρ represents the formation fluid density, g represents the gravitational acceleration, h1 represents the depth of the oil layer, and h2 represents the depth of the dynamic fluid level.

[0196] In a specific embodiment of the present invention, there are multiple second production wells, and each second production well is located in the same well group. The device further includes a distribution map drawing module, which is used to draw a planar distribution map of the steam chamber leading edge of the well group where the second production well is located based on the position coordinates of the leading edge of the steam chamber of each second production well.

[0197] On the other hand, embodiments of the present invention also provide a machine-readable storage medium having a computer program stored thereon, wherein the computer program, when executed by a processor, implements the method for predicting the steam chamber in a steam drive as described in the above embodiments.

[0198] In another aspect, embodiments of the present invention also provide a computer device, including a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor executes the program to implement the method for predicting the steam chamber in the steam drive described in the above embodiments.

[0199] In one specific embodiment, the steam chamber prediction device 400 in a steam drive provided by the present invention can be implemented as a computer program that can run on a computer device. The memory of the computer device can store the various program modules that make up the steam chamber prediction device 400 in the steam drive. The computer program, composed of the various program modules, causes a processor to execute the steps in the steam chamber prediction method in a steam drive described in this specification.

[0200] This invention also provides a computer program product that, when executed on a data processing device, is suitable for executing a program that initializes the following method steps:

[0201] The correlation between the wellhead production characteristics of the first production well and the average bottom hole temperature is determined, and the bottom hole temperature of the second production well is determined based on the wellhead production characteristics of the second production well using this correlation.

[0202] Calculate the bottom hole pressure of the second production well;

[0203] By comparing the bottom temperature of the second production well with the bottom temperature of the steam injection well in the same well group as the second production well, and by comparing the bottom pressure of the second production well with the bottom pressure of the steam injection well, the steam chamber at the bottom of the second production well can be identified.

[0204] The first production well is a production well with bottom hole temperature monitoring data, and the second production well is a production well without bottom hole temperature monitoring data.

[0205] The device embodiments described above are merely illustrative. The units described as separate components may or may not be physically separate. The components shown as units may or may not be physical units; that is, they may be located in one place or distributed across multiple network units. Some or all of the modules can be selected to achieve the purpose of this embodiment according to actual needs. Those skilled in the art can understand and implement this without any creative effort.

[0206] Those skilled in the art will understand that embodiments of the present invention can be provided as methods, systems, or computer program products. Therefore, the present invention can take the form of a completely hardware embodiment, a completely software embodiment, or an embodiment combining software and hardware aspects. Furthermore, the present invention can take the form of a computer program product embodied on one or more computer-usable storage media (including, but not limited to, disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0207] It should also be noted that the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such process, method, article, or apparatus. Unless otherwise specified, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes that element.

[0208] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention, and not to limit them; although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some of the technical features; and these modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the embodiments of the present invention.

Claims

1. A method for predicting the steam chamber in a steam-driven process, characterized in that, include: The correlation between the wellhead production characteristics and bottom hole temperature of the first production well is determined, and the bottom hole temperature of the second production well is determined based on the wellhead production characteristics of the second production well using this correlation. Calculate the bottom hole pressure of the second production well; By comparing the bottom temperature of the second production well with the bottom temperature of the steam injection well in the same well group as the second production well, and by comparing the bottom pressure of the second production well with the bottom pressure of the steam injection well, the steam chamber at the bottom of the second production well can be identified. The first production well is a production well with bottom hole temperature monitoring data, and the second production well is a production well without bottom hole temperature monitoring data.

2. The method according to claim 1, characterized in that, The process of determining the correlation between the wellhead production characteristics and the bottom hole temperature of the first production well, and using this correlation to determine the bottom hole temperature of the second production well based on its wellhead production characteristics, includes: Establish a graph showing the relationship between the wellhead production temperature, wellhead production rate, and bottom hole temperature of the first production well. Find the bottom temperature of the second production well corresponding to the wellhead production temperature and wellhead production volume of the second production well from the relationship diagram.

3. The method according to claim 2, characterized in that, Establish a graph showing the relationship between the wellhead production temperature, wellhead production rate, and bottom hole temperature of the first production well, including: By correlating the changes in wellhead production temperature and production volume of the first production well recorded at different times with the changes in bottom hole temperature of the first production well monitored at different times, a combination of wellhead production temperature, wellhead production volume and bottom hole temperature for the same period is obtained. Based on the preset range into which the wellhead production falls, the combination of wellhead production temperature, wellhead production, and bottom hole temperature is categorized into the corresponding preset range. Curve fitting was performed on the wellhead production temperature and bottom hole temperature classified into each preset interval to obtain the relationship between the wellhead production temperature and bottom hole temperature in each preset interval. Based on the aforementioned relationships, plot the relationship between wellhead production temperature and bottom hole temperature under different preset intervals; The preset interval is a range divided according to the amount of fluid produced at the wellhead.

4. The method according to claim 1, characterized in that, The step of comparing the bottom-hole temperature of the second production well with the bottom-hole temperature of the steam injection wells in the same well group as the second production well, and comparing the bottom-hole pressure of the second production well with the bottom-hole pressure of the steam injection wells to identify the steam chamber at the bottom of the second production well, includes: Based on the bottom-hole temperature of the second production well, the bottom-hole temperature of the steam injection well in the well group where the second production well is located, the bottom-hole pressure of the second production well, and the bottom-hole pressure of the steam injection well, the temperature distribution map between the second production well and the steam injection well is determined by interpolation. The temperature at the leading edge of the steam chamber is identified by utilizing the relationship between saturated steam pressure and temperature. The spatial coordinates of the temperature at the leading edge of the steam chamber in the temperature distribution map are determined, and these spatial coordinates are used as the position coordinates of the leading edge of the steam chamber at the bottom of the second production well.

5. The method according to claim 4, characterized in that, The step of determining the temperature distribution map between the second production well and the steam injection well using interpolation based on the bottom-hole temperature of the second production well, the bottom-hole temperature of the steam injection well in the same well group as the second production well, the bottom-hole pressure of the second production well, and the bottom-hole pressure of the steam injection well includes: The distance between the second production well and the steam injection wells in the well group where the second production well is located is evenly divided into segments to obtain the spatial coordinates of each segment point; Using the constraint that the temperature value at each segment point increases uniformly from the bottom temperature of the second production well to the bottom temperature of the steam injection well, interpolation is performed to obtain the temperature value at the spatial coordinates of each segment point other than the segment points where the second production well and the steam injection well are located, so that the absolute value of the temperature difference between any two adjacent segment points is equal. A temperature distribution map between the second production well and the steam injection well is drawn based on the temperature values ​​of each segment point. The segment points where the second production well and the steam injection well are located are associated with the pressure values ​​at their own spatial coordinates.

6. The method according to claim 5, characterized in that, The method of determining the temperature distribution map between the second production well and the steam injection well using interpolation based on the bottom-hole temperature of the second production well, the bottom-hole temperature of the steam injection well in the well group where the second production well is located, the bottom-hole pressure of the second production well, and the bottom-hole pressure of the steam injection well, further includes: Using the constraint that the pressure value at each segment point increases uniformly from the bottom pressure of the second production well to the bottom pressure of the steam injection well, interpolation is used to obtain the pressure value at the spatial coordinates of each segment point other than the segment points where the second production well and the steam injection well are located, so that the absolute value of the pressure difference between any two adjacent segment points is equal. Within the temperature distribution map, the temperature values ​​at the spatial coordinates of all segment points except those of the second production well and the steam injection well are correlated one-to-one with the pressure values ​​at the spatial coordinates of each segment point.

7. The method according to claim 1, characterized in that, The calculation of the bottom hole pressure of the second production well includes: The bottom pressure of the second production well was calculated based on the dynamic fluid level monitoring data of the second production well.

8. The method according to claim 7, characterized in that, The step of calculating the bottom hole pressure of the second production well based on the dynamic fluid level monitoring data of the second production well includes: Based on the oil layer depth of the second production well and the dynamic fluid level depth obtained from the dynamic fluid level monitoring data of the second production well, the bottom hole pressure of the second production well is calculated using Formula 1. Formula 1 is: P = ρg(h1-h2), where P represents the bottom hole pressure of the second production well, ρ represents the formation fluid density, g represents the gravitational acceleration, h1 represents the depth of the oil layer, and h2 represents the depth of the dynamic fluid level.

9. The method according to claim 1, characterized in that, The second production well is multiple, and each second production well is located in the same well group. The method further includes: Based on the position coordinates of the leading edge of the steam chamber of each second production well, draw a planar distribution diagram of the leading edge of the steam chamber of the well group where the second production well is located.

10. A predictive device for the steam chamber in a steam-driven system, characterized in that, include: The correlation determination module is used to determine the correlation between the wellhead production characteristics and the bottom hole temperature of the first production well, and to use this correlation to determine the bottom hole temperature of the second production well based on the wellhead production characteristics of the second production well. The bottom hole pressure calculation module is used to calculate the bottom hole pressure of the second production well. The steam chamber identification module is used to compare the bottom temperature of the second production well with the bottom temperature of the steam injection well in the well group where the second production well is located, and to compare the bottom pressure of the second production well with the bottom pressure of the steam injection well, so as to identify the steam chamber at the bottom of the second production well. The first production well is a production well with bottom hole temperature monitoring data, and the second production well is a production well without bottom hole temperature monitoring data.

11. The apparatus according to claim 10, characterized in that, The process of determining the correlation between the wellhead production characteristics and the bottom hole temperature of the first production well, and using this correlation to determine the bottom hole temperature of the second production well based on its wellhead production characteristics, includes: Establish a graph showing the relationship between the wellhead production temperature, wellhead production rate, and bottom hole temperature of the first production well. Find the bottom temperature of the second production well corresponding to the wellhead production temperature and wellhead production volume of the second production well from the relationship diagram.

12. The apparatus according to claim 11, characterized in that, Establish a graph showing the relationship between the wellhead production temperature, wellhead production rate, and bottom hole temperature of the first production well, including: By correlating the changes in wellhead production temperature and production volume of the first production well recorded at different times with the changes in bottom hole temperature of the first production well monitored at different times, a combination of wellhead production temperature, wellhead production volume and bottom hole temperature for the same period is obtained. Based on the preset range into which the wellhead production falls, the combination of wellhead production temperature, wellhead production, and bottom hole temperature is categorized into the corresponding preset range. Curve fitting was performed on the wellhead production temperature and bottom hole temperature classified into each preset interval to obtain the relationship between the wellhead production temperature and bottom hole temperature in each preset interval. Based on the aforementioned relationships, plot the relationship between wellhead production temperature and bottom hole temperature under different preset intervals; The preset interval is a range divided according to the amount of fluid produced at the wellhead.

13. The apparatus according to claim 10, characterized in that, The step of comparing the bottom-hole temperature of the second production well with the bottom-hole temperature of the steam injection wells in the same well group as the second production well, and comparing the bottom-hole pressure of the second production well with the bottom-hole pressure of the steam injection wells to identify the steam chamber at the bottom of the second production well, includes: Based on the bottom-hole temperature of the second production well, the bottom-hole temperature of the steam injection well in the well group where the second production well is located, the bottom-hole pressure of the second production well, and the bottom-hole pressure of the steam injection well, the temperature distribution map between the second production well and the steam injection well is determined by interpolation. The temperature at the leading edge of the steam chamber is identified by utilizing the relationship between saturated steam pressure and temperature. The spatial coordinates of the temperature at the leading edge of the steam chamber in the temperature distribution map are determined, and these spatial coordinates are used as the position coordinates of the leading edge of the steam chamber at the bottom of the second production well.

14. The apparatus according to claim 13, characterized in that, The step of determining the temperature distribution map between the second production well and the steam injection well using interpolation based on the bottom-hole temperature of the second production well, the bottom-hole temperature of the steam injection well in the same well group as the second production well, the bottom-hole pressure of the second production well, and the bottom-hole pressure of the steam injection well includes: The distance between the second production well and the steam injection wells in the well group where the second production well is located is evenly divided into segments to obtain the spatial coordinates of each segment point; Using the constraint that the temperature value at each segment point increases uniformly from the bottom temperature of the second production well to the bottom temperature of the steam injection well, interpolation is performed to obtain the temperature value at the spatial coordinates of each segment point other than the segment points where the second production well and the steam injection well are located, so that the absolute value of the temperature difference between any two adjacent segment points is equal. A temperature distribution map between the second production well and the steam injection well is drawn based on the temperature values ​​of each segment point. The segment points where the second production well and the steam injection well are located are associated with the pressure values ​​at their own spatial coordinates.

15. The apparatus according to claim 14, characterized in that, The method of determining the temperature distribution map between the second production well and the steam injection well using interpolation based on the bottom-hole temperature of the second production well, the bottom-hole temperature of the steam injection well in the well group where the second production well is located, the bottom-hole pressure of the second production well, and the bottom-hole pressure of the steam injection well, further includes: Using the constraint that the pressure value at each segment point increases uniformly from the bottom pressure of the second production well to the bottom pressure of the steam injection well, interpolation is used to obtain the pressure value at the spatial coordinates of each segment point other than the segment points where the second production well and the steam injection well are located, so that the absolute value of the pressure difference between any two adjacent segment points is equal. Within the temperature distribution map, the temperature values ​​at the spatial coordinates of all segment points except those of the second production well and the steam injection well are correlated one-to-one with the pressure values ​​at the spatial coordinates of each segment point.

16. The apparatus according to claim 10, characterized in that, The calculation of the bottom hole pressure of the second production well includes: The bottom pressure of the second production well was calculated based on the dynamic fluid level monitoring data of the second production well.

17. The apparatus according to claim 16, characterized in that, The step of calculating the bottom hole pressure of the second production well based on the dynamic fluid level monitoring data of the second production well includes: Based on the oil layer depth of the second production well and the dynamic fluid level depth obtained from the dynamic fluid level monitoring data of the second production well, the bottom hole pressure of the second production well is calculated using Formula 1. Formula 1 is: P = ρg(h1-h2), where P represents the bottom hole pressure of the second production well, ρ represents the formation fluid density, g represents the gravitational acceleration, h1 represents the depth of the oil layer, and h2 represents the depth of the dynamic fluid level.

18. The apparatus according to claim 10, characterized in that, There are multiple second production wells, and each second production well is located in the same well group. The device also includes a distribution map drawing module, which is used to draw a planar distribution map of the steam chamber leading edge of the well group where the second production well is located based on the position coordinates of the leading edge of the steam chamber of each second production well.

19. A computer device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that, When the processor executes the program, it implements the method for predicting the steam chamber in a steam drive as described in any one of claims 1-9.

20. A machine-readable storage medium having a computer program stored thereon, characterized in that, When the computer program is executed by the processor, it implements the method for predicting the steam chamber in the steam drive as described in any one of claims 1-9.

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