Method for determining water-mixing temperature-raising parameters of oil well borehole

Abstract

The present application relates to the technical field of oil production engineering, and particularly relates to a method for determining water-mixing and temperature-raising parameters of an oil well wellbore, which aims to solve the technical problem that the water-mixing and temperature-raising process cannot determine the water-mixing amount and the mixed water temperature in the related art. The method for determining water-mixing and temperature-raising parameters of an oil well wellbore comprises the following steps: S1: finding out a relationship function corresponding to the wellhead produced liquid temperature and the produced liquid amount of an oil well in different seasons; S2: according to the produced liquid amount Q1 of a target oil well, selecting a corresponding relationship function to calculate the original produced liquid temperature T1 of the target oil well; S3: setting a new produced liquid temperature T0 of the target oil well, and according to an energy conservation calculation formula Q2T2=k(Q1+Q2)T0-Q1T1, calculating the required water-mixing amount Q2 and the water-mixing temperature T2 of the target oil well, wherein T0 is greater than the crude oil freezing point of the target oil well, and the coefficient k is 0.7-1. According to the production basic data of the oil well, the method simulates and calculates the required water-mixing amount and the water-mixing temperature of the wellbore water-mixing and temperature-raising process, and provides data guidance for the wellbore water-mixing process.

Description

Technical Field

[0001] This invention relates to the field of oil production engineering technology, and in particular to a method for determining the parameters for water injection and temperature enhancement in oil wells. Background Technology

[0002] During the extraction of crude oil from the formation, as the temperature and pressure inside the wellbore decrease, waxy and asphaltene will precipitate and adhere to the tubing and sucker rod, thereby increasing the load on the pumping unit and the power consumption. In severe cases, it may even cause the well to become clogged and unable to produce normally.

[0003] Currently, conventional wax removal and viscosity reduction processes mainly include chemical wax removal and prevention, hot washing, and electric heating. However, for oil wells with high pour point, high viscosity, and high wax content, these processes still suffer from unsatisfactory wax removal and prevention effects and high operating costs. To address this, a water-injection and temperature-raising method has been proposed. This involves using a heating device at the wellhead to raise the temperature, then injecting hot water into the wellbore to maintain the wellbore temperature above the wax precipitation point, or using high-temperature water injection to achieve wax removal and viscosity reduction. This method can replace conventional wax removal and prevention processes. However, it should be noted that there is currently no method for determining the amount and temperature of the water injected. This leads to unclear assessment of the adaptability conditions for the wellbore water injection process, unclear on-site management systems, and difficulty in guaranteeing the effectiveness of large-scale application. Summary of the Invention

[0004] The purpose of this invention is to provide a method for determining the parameters of water injection for temperature enhancement in oil wells, so as to solve the technical problem in related technologies that the amount and temperature of water injection cannot be determined in the water injection process.

[0005] To solve the above-mentioned technical problems, the technical solution provided by the present invention is as follows:

[0006] This invention provides a method for determining the parameters for water injection and temperature enhancement in oil wells, comprising the following steps:

[0007] S1: Find the relationship function between the wellhead produced fluid temperature and the produced fluid volume in different quarters of the oil well;

[0008] S2: Based on the production volume Q1 of the target oil well, select the corresponding relationship function to calculate the original production temperature T1 of the target oil well;

[0009] S3: Set the new produced fluid temperature T0 of the target oil well. According to the energy conservation formula Q2T2=k(Q1+Q2)T0-Q1T1, calculate the required water injection amount Q2 and water injection temperature T2 of the target oil well. T0 is greater than the freezing point of crude oil in the target oil well, and the coefficient k is taken as 0.7-1.

[0010] Furthermore, in step S1, the method for determining the relational function is as follows:

[0011] S101: Select n sample oil wells in the target block, and test the produced fluid temperature of the n sample oil wells once a quarter, where n≥5;

[0012] S102: Based on the data measured in step S101, plot a scatter matrix for each quarter with the liquid production volume as the abscissa and the liquid production temperature as the ordinate, and calculate the linear function of each quarter from the scatter matrix.

[0013] Furthermore, during step S101, an oil well using tubing of the same specification is selected as the sample oil well, and tools affecting wellbore temperature are removed from the tubing string of the sample oil well.

[0014] Furthermore, during step S102, if the square value R of the correlation coefficient between the product volume and the product temperature is... 2 If R < 0.7, then return to step S101. 2 If the value is ≥0.7, then the linear function in one variable is used as the relational function.

[0015] Furthermore, in step S2, if Q1 is the production volume of the target oil well in spring, then the relationship function of the target oil well in spring is selected, and so on.

[0016] Furthermore, in step S3, the water mixing temperature T2 is 55-90℃.

[0017] Furthermore, in step S3, with the load at the suspension point on the dynamometer card as the objective function, the value of Q2T2 is dynamically adjusted when the maximum increase in the suspension point load exceeds a limit value, or the minimum decrease in the load exceeds a limit value.

[0018] Furthermore, the method for determining the water injection and temperature-raising parameters in the oil wellbore also includes the following steps:

[0019] S4: Based on the water injection volume Q2 and water injection temperature T2 obtained in step S3, hot water that meets the parameters is injected into the wellbore of the target oil well through the annulus.

[0020] Furthermore, during step S4, a wellhead heating device is installed at the wellhead of the target oil well to heat the water.

[0021] Furthermore, the wellhead heating equipment is composed of a solar concentrator, an electric heating auxiliary heating device, and a heat storage device.

[0022] Based on the above technical solution, the technical effect that the method for determining the water injection and temperature raising parameters of oil wells provided by the present invention can achieve is as follows:

[0023] This method, based on the production data of oil wells, derives the relationship function between the wellhead produced fluid temperature and production volume in different quarters. Combined with the energy conservation formula Q2T2=k(Q1+Q2)T0-Q1T1, simulation calculations can determine the required water injection volume and temperature for wellbore temperature enhancement. Applying this method to oil wells with high pour point, high viscosity, and high wax content crude oil can achieve the goal of increasing wellbore temperature and preventing blockage caused by temperature and pressure drops during wellbore lifting. Attached Figure Description

[0024] To more clearly illustrate the specific embodiments of the present invention or the technical solutions in the prior art, the drawings used in the description of the specific embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are some embodiments of the present invention. For those skilled in the art, other drawings can be obtained from these drawings without creative effort.

[0025] Figure 1 A flowchart of a method for determining oil wellbore water injection and temperature raising parameters provided in an embodiment of the present invention;

[0026] Figure 2 A data table of wellhead produced fluid temperature and produced fluid volume provided for Embodiment 1 of the present invention;

[0027] Figure 3 A scatter matrix diagram of the relationship between wellhead produced fluid temperature and produced fluid volume in Embodiment 1 of the present invention;

[0028] Figure 4 The energy consumption data table for Embodiment 1 of the present invention. Detailed Implementation

[0029] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. The components of the embodiments of the present invention described and shown in the accompanying drawings can generally be arranged and designed in various different configurations.

[0030] Therefore, the following detailed description of the embodiments of the invention provided in the accompanying drawings is not intended to limit the scope of the claimed invention, but merely to illustrate selected embodiments of the invention. All other embodiments obtained by those skilled in the art based on the embodiments of the invention without inventive effort are within the scope of protection of the invention.

[0031] The following detailed description of some embodiments of the present invention is provided in conjunction with the accompanying drawings. Unless otherwise specified, the following embodiments and features can be combined with each other.

[0032] Water addition and temperature increase can replace conventional wax removal and prevention processes, but there is currently no method to determine the amount and temperature of water to be added. This leads to unclear assessment of the adaptability conditions of the wellbore water addition process, unclear on-site management system, and difficulty in guaranteeing the effect of large-scale application.

[0033] In view of this, the present invention provides a method for determining the parameters for water injection and temperature increase in oil wellbore, comprising the following steps:

[0034] S1: Find the relationship function between the wellhead produced fluid temperature and the produced fluid volume of the oil well in different quarters; S2: Based on the produced fluid volume Q1 of the target oil well, select the corresponding relationship function and calculate the original produced fluid temperature T1 of the target oil well; S3: Set the new produced fluid temperature T0 of the target oil well, and calculate the required water injection volume Q2 and water injection temperature T2 of the target oil well according to the energy conservation formula Q2T2=k(Q1+Q2)T0-Q1T1, where T0 is greater than the freezing point of the crude oil of the target oil well, and the coefficient k is taken as 0.7-1.

[0035] This method, based on the production data of oil wells, derives the relationship function between the wellhead produced fluid temperature and production volume in different quarters. Combined with the energy conservation formula Q2T2=k(Q1+Q2)T0-Q1T1, simulation calculations can determine the required water injection volume and temperature for wellbore temperature enhancement. Applying this method to oil wells with high pour point, high viscosity, and high wax content crude oil can achieve the goal of increasing wellbore temperature and preventing blockage caused by temperature and pressure drops during wellbore lifting.

[0036] The following combination Figures 1 to 4 The method for determining the water-injection temperature-raising parameters in oil wells provided in this embodiment is described in detail below:

[0037] refer to Figure 1 The method for determining the water injection temperature-raising parameters in oil wells is as follows:

[0038] Step 1: Select n sample oil wells in the target block and test the wellhead produced fluid temperature of the n sample oil wells once per quarter. Here, n≥5, the sample oil wells should use the same specification tubing, and ensure that no tools that affect the wellbore temperature are run into the tubing string.

[0039] Step 2: Based on the test data from Step 1, plot four scatter plots with the product output as the x-axis and the product temperature as the y-axis, and then fit the scatter plot values ​​to a linear relationship curve. Here, if R... 2If the value is less than 0.7, return to step 1 and retest; otherwise, use the functions represented by each linear relationship curve as the relationship functions between wellhead produced fluid temperature and produced fluid volume for the four quarters. It should also be noted that the relationship functions are affected by various factors such as formation temperature and geothermal gradient, and different oilfield blocks will yield different results.

[0040] Step 3: Based on the production rate Q1 of the target oil well, predict the wellhead production temperature T1 for each quarter using the relationship function between wellhead production temperature and production rate. Here, each quarter represents spring, summer, autumn, and winter, with the lowest wellhead production temperature occurring in winter due to the influence of ground temperature.

[0041] Step 4: Based on the set wellhead temperature T0 of the newly produced fluid, calculate the required water injection volume Q2 and injection temperature T2 for each quarter. The calculation formula is Q2T2=k(Q1+Q2)T0-Q1T1. Here, the temperature of the newly produced fluid T0 should be greater than the freezing point of the crude oil in the well. T2 is generally taken between 55℃ and 90℃, such as 55℃, 75℃, or 90℃. The value of k is generally taken between 0.7 and 1, such as 0.7, 0.9, or 1.

[0042] Step 5: Use wellhead heating equipment to raise the temperature. Each quarter, according to the set water injection volume Q2 and water injection temperature T2, hot water is injected into the wellbore through the annulus. The required Q2 and T2 values ​​are the largest in winter, which plays a role in continuous wax prevention in the wellbore. Additionally, the suspension point load on the indicator diagram can be used as the objective function. When the maximum increase in the suspension point load exceeds the limit value, or the minimum decrease in the load exceeds the limit value, the Q2 and T2 values ​​are dynamically adjusted to remove wax and reduce heat loss. The wellhead heating equipment should fully consider the well site area and should not affect well pump inspection and maintenance operations. Optionally, a high-efficiency solar concentrator can be used, along with an auxiliary electric heating device and a heat storage device, to ensure that the water injection volume and temperature continuously meet the requirements.

[0043] This method for determining the parameters for water injection and temperature enhancement in oil wells is based on the well's production data. Through simulation calculations, the required water injection volume and temperature are determined, providing parameter guidance for wellhead heating equipment and the water injection process for wax removal and prevention in the wellbore. The method utilizes wellhead heating equipment to inject pre-set hot water into the wellbore through the annulus, raising the wellbore temperature above the crude oil's wax precipitation point, thus achieving the goal of wax prevention and viscosity reduction. This method is applicable to oil wells with high pour point, high viscosity, and high wax content crude oil. It can increase the wellbore temperature and prevent solidification problems caused by temperature and pressure drops during wellbore lifting. Furthermore, compared to conventional wellbore heating devices, especially hollow sucker rod cable heating technology, this method significantly reduces power consumption, sustainably performs wax prevention, wax removal, and viscosity reduction in the wellbore, has low operating costs, and a wide range of applications.

[0044] To make the objectives, technical solutions, and advantages of the present invention clearer, the embodiments of the present invention will be further described in detail below through Example 1.

[0045] In the application of the Harbin 34-68X well, the temperature of the produced fluid at the wellhead has always been maintained above 35℃, realizing the replacement of the hollow rod electric heating in the wellbore.

[0046] Step 1: Reference Figure 2 Six sample oil wells in the Ha34 fault block were selected to test the temperature of the produced fluid in winter.

[0047] Step 2: Based on the test data, plot a scatter plot with production volume as the x-axis and production temperature as the y-axis. Fit the plot to obtain the linear relationship function between wellhead production temperature and production volume: y = 0.5508x + 14.938, R0. 2 =0.7331, such as Figure 3 As shown.

[0048] Step 3: Input the production fluid volume of Ha34-68X as 8.5t / d, and calculate the wellhead production fluid temperature as 19.62℃.

[0049] Step 4: Based on the solidification point of the crude oil in the fault block, the temperature of the newly produced fluid at the wellhead is set to 35℃. According to the calculation formula Q2T2=k(Q1+Q2)T0-Q1T1, k is taken as 1, and the water injection rate is set to 6t / d. The required water injection temperature is calculated to be 56.8℃.

[0050] Step 5: The wellhead was heated using a dual-slot, dual-axis solar concentrator. Due to the large capacity of the collector, the water injection temperature was set at 56.8℃, and the actual water injection rate reached 9.6t / d. The calculated temperature of the newly produced fluid at the wellhead was 39.1℃. Actual field tests showed that the average temperature of the produced fluid in September reached 41℃, which was basically consistent with the calculated results. This also met the well's requirements for wax removal and successfully replaced the hollow sucker rod cable heating device.

[0051] In the Ha 34 fault block, the replacement of hollow sucker rod cable heating was applied to 9 wells, as a reference. Figure 4 With an average water injection rate of 8.5 t / d, a water injection temperature of 65℃, and a wellhead produced fluid temperature of 39℃, the annual electricity consumption for replacing electric heating is 1,599,400 kWh. After deducting the annual electricity consumption of the solar auxiliary heating device (155,000 kWh), and assuming an electricity price of 0.59 yuan / kWh, the annual electricity savings are 852,200 kWh, and savings on well cleaning and chemical costs are 78,400 yuan, totaling 930,600 yuan in savings. Furthermore, the power consumption of the pumping unit remains essentially unchanged, mainly because the original produced fluid volume of the well is low. After water injection, the original production parameters can basically meet the fluid discharge requirements, avoiding pump dry running. Additionally, the increased temperature after water injection reduces the viscosity of the crude oil, further reducing power consumption. Overall, the power consumption of the pumping unit remains essentially unchanged.

[0052] 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 or all of the technical features; and these modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the scope of the technical solutions of the embodiments of the present invention.

Claims

1. A method for determining parameters for water injection to raise the temperature in an oil wellbore, characterized in that, Includes the following steps: S1: Find the relationship function between the wellhead produced fluid temperature and the produced fluid volume in different quarters of the oil well; S2: Based on the production volume Q1 of the target oil well, select the corresponding relationship function to calculate the original production fluid temperature T1 of the target oil well; S3: Set the new produced fluid temperature T0 of the target oil well, and calculate the required water injection amount Q2 and water injection temperature T2 of the target oil well according to the energy conservation calculation formula Q2T2=k(Q1+Q2)T0-Q1T1, where T0 is greater than the freezing point of crude oil in the target oil well, and the coefficient k is taken as 0.7-1. In step S1, the method for determining the relational function is as follows: S101: Select n sample oil wells in the target block, and test the produced fluid temperature of the n sample oil wells once a quarter, where n≥5; S102: Based on the data measured in step S101, plot a scatter matrix for each quarter with the liquid production volume as the abscissa and the liquid production temperature as the ordinate, and calculate the linear function of each quarter from the scatter matrix. When performing step S102, if the square value R of the correlation coefficient between the product volume and the product temperature is... 2 If R < 0.7, then return to step S101. 2 If ≥0.7, then the linear function in one variable is used as the relational function; In step S3, the load at the suspension point on the indicator diagram is used as the objective function. When the maximum increase in the suspension point load exceeds the limit value, or the minimum decrease in the load exceeds the limit value, the value of Q2T2 is dynamically adjusted.

2. The method for determining the water-injection temperature-raising parameters in an oil wellbore according to claim 1, characterized in that, When performing step S101, an oil well using tubing of the same specification is selected as the sample oil well, and tools that affect the wellbore temperature are removed from the tubing string of the sample oil well.

3. The method for determining the water-injection temperature-raising parameters in an oil wellbore according to claim 1, characterized in that, In step S2, if Q1 is the production volume of the target oil well in spring, then the relationship function of the target oil well in spring is selected, and so on.

4. The method for determining the water-injection temperature-raising parameters in an oil wellbore according to claim 1, characterized in that, In step S3, the water mixing temperature T2 is 55-90℃.

5. The method for determining the water-injection temperature-raising parameters of an oil wellbore according to any one of claims 1 to 4, characterized in that, The method for determining the water injection and temperature-raising parameters in the oil wellbore also includes the following steps: S4: Based on the water injection volume Q2 and water injection temperature T2 obtained in step S3, hot water that meets the parameters is injected into the wellbore of the target oil well through the annulus.

6. The method for determining the water-injection temperature-raising parameters in an oil wellbore according to claim 5, characterized in that, During step S4, a wellhead heating device is installed at the wellhead of the target oil well to heat the water.

7. The method for determining the water-injection temperature-raising parameters in an oil wellbore according to claim 6, characterized in that, The wellhead heating equipment is composed of a solar concentrator, an electric heating auxiliary device, and a heat storage device.

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