A method for accurately sealing and fixing a faulted sand and rock well region

Abstract

The application relates to the technical field of sealing control, in particular to a precise sealing method for a broken sand and rock well area, which comprises the following steps: determining the positions of the sand consolidation wellbores based on the original wellbore position; acquiring the bottom hole pressure, the actual injection flow rate, the squeeze pressure and the flowback flow rate of each sand consolidation wellbore in the sealing process in real time; based on the difference between the discrete degree of the flowback flow rate and the actual injection flow rate in each cycle, the change trend of the bottom hole pressure data, the size and the relative fluctuation degree of the squeeze pressure data of each cycle, and the difference between the total cement slurry injection amount and the preset total cement slurry amount until the end of each cycle, the adjustment range of each cycle is constructed; and based on the adjustment range and the actual injection flow rate of the current cycle, the injection flow rate parameter of the grouting pump in the next cycle is adjusted. The injection flow rate parameter of the grouting pump in the sealing process of each sand consolidation wellbore is adaptively adjusted, so that the stability and the construction safety of the sealing process are improved.

Description

Technical Field

[0001] This application relates to the field of sealing control technology, specifically to a precise sealing method for the area of ​​a well that discharges sand and rock. Background Technology

[0002] Misaligned casing wells, characterized by continuous sand and rock discharge from the fracture site, are a type of well where the casing has fractured. During conventional casing flushing, single connections are required during the operation. If the fracture site is still discharging sand and rock at this time, the discharged debris accumulates inside the wellbore, causing repeated sand level rises and even leading to casing backing up. While existing solutions employ "in-well sand-stabilizing agent injection" to address this issue, they still suffer from drawbacks such as blindly targeting the sand-stabilizing area, poor wellbore stability, and low operational efficiency. Therefore, developing a precise sealing method for misaligned casing wells is of great significance for achieving precise sealing of the sand- and rock-discharging area outside the casing, improving wellbore stability, and enhancing operational efficiency.

[0003] During well cementation, the injection flow rate directly affects the fluid flow pattern within the wellbore and the replacement effect of the cement slurry on the original drilling fluid. Current technologies typically employ a preset fixed injection flow rate for injection-displacement control to ensure the stability of the construction process. However, due to significant differences between different wells in terms of formation pressure capacity, sand and rock expulsion strength, casing fault morphology, and wellbore geometry, and because the injection-displacement process exhibits distinct stages, using a fixed injection flow rate makes it difficult to accurately reflect the actual fluid movement within the well and to promptly identify different operating conditions such as well leakage, fracture propagation, or normal pressure buildup. This can easily lead to a mismatch between the injection flow rate and the downhole conditions, resulting in problems such as fluid bypass flow or restricted injection, affecting the cementation effect and construction safety. Summary of the Invention

[0004] To address the aforementioned technical problems, this application provides a method for precise sealing of the sand- and rock-producing well area in case of misalignment, thereby resolving the existing issues.

[0005] The present application proposes a method for precise sealing of areas in wells that expel sand and rock during misalignment, employing the following technical solution:

[0006] One embodiment of this application provides a method for precise sealing of a faulted well area that produces sand and rock, the method comprising the following steps:

[0007] The location of each sand-stabilizing well is determined based on the original wellbore location; the bottom hole pressure, actual injection flow rate, squeezing pressure, and backflow flow rate of each sand-stabilizing well are acquired in real time during the sealing process;

[0008] The bottom hole pressure data is corrected by using the actual injection flow rate data of each sand-fixing well in each cycle. Based on the difference between the dispersion of the backflow flow rate and the actual injection flow rate in each cycle, and the proportion of the decay times of the corrected bottom hole pressure data in all trend changes, the injection displacement risk index of each cycle is constructed.

[0009] Based on the difference between the maximum squeezing pressure and the preset formation ultimate pressure in each cycle, as well as the relative fluctuation of the squeezing pressure data, a pressure stagnation and instability index for each cycle is constructed.

[0010] Based on the difference between the total cement grout injection volume up to the end of each cycle and the preset total cement grout volume, the grouting schedule for each cycle is constructed. Combined with the grouting risk index and pressure instability index for each cycle, the adjustment range for each cycle is constructed. Based on the adjustment range of the current cycle and the actual injection flow rate, the injection flow rate parameter of the grouting pump in the next cycle is adjusted.

[0011] Preferably, the location of each sand-fixing wellbore refers to three sand-fixing wellbore locations evenly distributed at a central angle of 120° on a circle centered on the original wellbore and with a preset radius.

[0012] Preferably, the specific process of correcting the bottom hole pressure data using the actual injection flow rate data of each sand-fixing wellbore in each cycle is as follows:

[0013] The sequence of bottom hole pressure data from each period, arranged in chronological order, is used as input to a sequence segmentation algorithm to obtain multiple pressure subsequences.

[0014] Based on the position range corresponding to each pressure subsequence, the actual injection flow data of the same period is synchronously divided into multiple corresponding injection flow subsequences;

[0015] The ratio between the normalized value of the mean of each pressure subsequence and the normalized value of the mean of the corresponding injection flow subsequence is recorded as the calibration pressure value of each pressure subsequence, thereby completing the correction of the bottom hole pressure data.

[0016] Preferably, the method for constructing the injection / substitution risk index for each period is as follows:

[0017] The ratio between the variance of the backflow flow data and the variance of the actual injection flow data for each period is calculated, and the absolute difference between this ratio and 1 is calculated.

[0018] The calibration pressure values ​​of all pressure subsequences in each period are arranged in chronological order to obtain the calibration pressure value sequence for each period.

[0019] The ratio between the number of negative numbers in the first-order difference sequence of the calibration pressure value sequence and the total length of the first-order difference sequence data is recorded as the anomaly ratio for each period.

[0020] The injection risk index for each period is positively correlated with the absolute difference and the abnormality ratio.

[0021] Preferably, the method for constructing the pressure buildup instability index for each cycle is as follows:

[0022] The ratio of the maximum value of the injection pressure data in each cycle to the preset formation ultimate pressure is calculated.

[0023] Based on the relative fluctuation of the injection pressure data in each period, a relative fluctuation coefficient for each period is constructed.

[0024] The pressure instability index for each period is positively correlated with the ratio and the relative volatility coefficient.

[0025] Preferably, the method for constructing the relative fluctuation coefficients for each period is as follows:

[0026] The mean of the absolute differences between all adjacent elements in the sequence of squeezing pressure data for each period, arranged in chronological order, is calculated and denoted as the squeezing fluctuation value for each period.

[0027] The average value of all injection pressure data for each period is calculated.

[0028] The ratio of the squeezing fluctuation value to the mean value is recorded as the relative fluctuation coefficient for each period.

[0029] Preferably, the replacement progress of each cycle refers to the ratio between the total amount of cement slurry injected up to the end of each cycle and the preset total amount of cement slurry to be injected during this replacement process.

[0030] Preferably, the method for obtaining the total amount of cement slurry injected up to the end of each cycle is as follows:

[0031] The product of the actual injection flow rate at each sampling time and the time interval between adjacent sampling times is recorded as the cement slurry injection volume at each sampling time.

[0032] The total cement slurry injection volume is calculated by summing the cement slurry injection volume at all sampling times from the start of data acquisition until the end of each cycle.

[0033] Preferably, the formula for calculating the adjustment amplitude of each cycle is: In the formula, Let be the adjustment range for the i-th cycle; The injection / replacement progress for the i-th cycle; Let be the injection risk index for the i-th period; Let be the pressure instability index for the i-th period.

[0034] Preferably, the specific formula for adjusting the injection flow rate parameter of the grouting pump in the next cycle is as follows: In the formula, The injection flow rate parameter of the grouting pump in the (i+1)th cycle; Set the minimum injection flow rate; The average value of the actual injected flow data in the i-th period; Let be the adjustment range for the i-th cycle; This is a preset adjustment factor; This is the function for finding the maximum value.

[0035] This application has at least the following beneficial effects:

[0036] This application addresses the problem in existing technologies where fixed injection flow parameters lead to inconsistent injection flow rates that cannot adapt to changes in downhole flow conditions and pressure bearing capacity, resulting in instability during the sealing process. By analyzing the fluctuation differences between the backflow flow and actual injection flow in each cycle, as well as the variation characteristics of bottom hole pressure data, an injection-displacement risk index is constructed. This allows for the analysis of leakage risks reflected by fluctuations in backflow flow and abnormal bottom hole pressure during the injection-displacement process. Furthermore, by analyzing the magnitude and fluctuation characteristics of the squeezing pressure in each cycle, a pressure buildup instability index is constructed, enabling the assessment of the degree of squeezing restriction after eliminating the influence of normal pressure buildup at the end of the injection-displacement period. Finally, by constructing an adjustment range, synergistic constraints on the flow state and squeezing pressure response during the injection-displacement process are achieved, thereby driving the injection flow parameters of the grouting pump to be dynamically corrected periodically. This reduces the risks of abnormal leakage and squeezing restriction, improving the stability and construction safety of the sealing process. Attached Figure Description

[0037] Figure 1 A flowchart illustrating the steps of a precise sealing method for a well area with alternating sand and rock discharge provided in this application;

[0038] Figure 2 The location distribution diagram of the sand-fixing wellbore relative to the original wellbore provided in this application. Detailed Implementation

[0039] The following, in conjunction with the accompanying drawings, details a specific scheme for a precise sealing method for a well area prone to sand and rock spillage, as provided in this application.

[0040] This application provides an embodiment of a method for precise sealing of a faulted well area that produces sand and rock. Specifically, it provides the following method for precise sealing of a faulted well area that produces sand and rock. Please refer to [link / reference]. Figure 1 The method includes the following steps:

[0041] Step 1: Determine the location of each sand-stabilizing well based on the original wellbore location; obtain the bottom hole pressure, actual injection flow rate, squeezing pressure, and backflow flow rate of each sand-stabilizing well in real time during the sealing process.

[0042] This application uses "CD26-SE33 well (Φ139.7mm casing, severe shallow sand production)" as an example to illustrate the sealing of a well with misaligned sand and rock production. The specific process for sealing a well with misaligned sand and rock production is as follows: First, the original wellbore is surveyed: a Φ118mm lead mold is printed down to 67.2m in the original wellbore, and the minimum diameter of the casing misalignment is measured to be Φ96mm. Based on historical construction data, 67-67.5m is determined to be the main sand and rock production section. Then, directional sand-stabilizing wellbore design is carried out: on a circle with the original wellbore as the center and R as the radius (R is a preset radius, determined to be 2m-5m based on formation fracture pressure testing; in this embodiment, R is taken as 2m), three sand-stabilizing wellbores (numbered 1#, 2#, and 3#) are evenly deployed at a central angle of 120°. The location distribution diagram of the sand-stabilizing wellbores relative to the original wellbore is shown below. Figure 2 As shown, multi-wellbore three-dimensional sand fixation covers the sand and rock extrusion area outside the misaligned casing, avoiding the problem of incomplete sand fixation in a single wellbore. It should be noted that before deploying and drilling directional sand-fixing wells, temporary sand-fixing gel is injected into the original wellbore to establish initial support, thereby avoiding the problem of collapse caused by drilling through multiple holes in unstable sand-extruding formations. Finally, each sand-fixing wellbore is used for layered sealing.

[0043] The sealing of each sand-stabilized wellbore is divided into shallow sealing and deep sealing. In this embodiment, the drilling depth for shallow sealing is 68m, and the drilling depth for deep sealing is 118m. This embodiment takes the shallow sealing process of sand-stabilized wellbore #1 as an example, and adaptively adjusts the injection flow rate during the sealing process to improve the sealing effect and construction safety.

[0044] Specifically, since the bottom-hole pressure can be calculated in real time using the density of the liquid inside the well, gravitational acceleration, and bottom-hole depth, this embodiment uses a density sensor to measure the density of the cement slurry in real time. Finally, based on the real-time collected cement slurry density and gravitational acceleration (9.8 m / s² in this embodiment), 2 The bottom hole pressure data is calculated in real time based on the bottom hole depth (i.e., the drilling depth for shallow sealing). The calculation method for bottom hole pressure data is a well-known technique, and the specific calculation process will not be described in detail here.

[0045] Subsequently, cement slurry is continuously injected into the sand-cementing wellbore using a cementing truck. At the start of the injection, the grouting pump is set to inject at a preset initial flow rate (0.8 in this embodiment). The cement slurry is injected and replaced, and the actual injection flow rate is collected in real time using the flow meter on the cementing truck. At the same time, the injection pressure of the cement slurry is collected synchronously using a pressure sensor installed at the high-pressure manifold of the cementing truck. The return slurry from the casing cementing is discharged from the two casing heads, so a tee is used to merge the fluid from the two casing heads into a single pipe flow, and an electromagnetic flow meter is used to measure the return flow rate in real time.

[0046] Data is collected from the moment the cement slurry begins to be injected. All data is collected synchronously and in real time. In this embodiment, the collection frequency of all types of data is 10Hz, and the sampling duration of 1 minute is recorded as a cycle.

[0047] In the first Q (3 in this embodiment) cycles, the injection displacement process is in its initial stage, and the injection flow rate is not adjusted. Taking the i-th cycle after the first Q cycles as an example, based on the bottom hole pressure data, actual injection flow rate data, squeezing pressure data, and flowback flow rate data collected in the i-th cycle, the bottom hole pressure sequence (in MPa) and injection flow rate sequence (in MPa) for the i-th cycle are constructed according to the time sequence of data collection. ), injection pressure sequence (in MPa), flowback flow sequence (in MPa) ).

[0048] Step 2: Correct the bottom hole pressure data using the actual injection flow rate data of each sand-fixing wellbore in each cycle. Based on the difference between the dispersion of the backflow flow rate and the actual injection flow rate in each cycle, and the proportion of the decay times of the corrected bottom hole pressure data in all trend changes, construct the injection displacement risk index for each cycle.

[0049] During normal cementing, after the cement slurry is transported to the bottom of the well via tubing, it gradually occupies the space of the original drilling fluid in the well and continuously displaces and discharges it. Since the cementing equipment operates according to the set injection flow rate, the cementing pressure passively changes with the downhole fluid transport resistance. Therefore, the discharge flow rate of the fluid returning from the well should usually be relatively stable and basically matched with the injection flow rate. Simultaneously, as the cement slurry is continuously injected, the available space for flow in the formation gradually decreases, the seepage channels contract, and the bottomhole pressure will show a slow upward trend.

[0050] However, considering the differences in the pressure-bearing capacity and permeability characteristics of different formations where oil wells are located, the initially set injection flow rate may be too high in some wells, which may induce formation fracturing or well leakage. This can cause some cement slurry to enter the deep formation or fractures without participating in the effective replacement of drilling fluid. In this case, the flowback flow rate will be lower than the injection flow rate and the fluctuation will be stronger. At the same time, the bottom hole pressure will show limited growth or abnormal fluctuations due to the appearance of a pressure relief channel. Therefore, the rationality of the currently set injection flow rate parameters can be preliminarily evaluated by analyzing the matching relationship between the injection flow rate and the flowback flow rate and the change characteristics of the bottom hole pressure.

[0051] It should be noted that since a retarder is added to the cement slurry, a 1-hour allowance is reserved for the initial setting time. Therefore, the thickening phenomenon of cement does not need to be considered during the injection process.

[0052] Let's take the i-th cycle as an example for analysis. First, we calculate the dispersion among the elements within the backflow sequence of the i-th cycle. The greater the dispersion of the backflow sequence, the more pronounced the fluctuations in the backflow, the more unstable the flow state, and the less it conforms to the stationarity of normal backflow. The calculation of dispersion is not limited to variance, standard deviation, and coefficient of variation; in this embodiment, variance is used for calculation.

[0053] Considering that the actual injection flow rate may fluctuate during the grouting process due to equipment or operating condition disturbances, resulting in inconsistencies between the actual collected injection flow rate and the preset injection flow rate parameters of the grouting pump, and that fluctuations in the injection flow rate can have a ripple effect on the return flow rate, the dispersion of the return flow rate sequence can be corrected and its dimensions eliminated by incorporating the injection flow rate.

[0054] The ratio of the dispersion of the backflow flow sequence in the i-th period to the dispersion of the injection flow sequence is denoted as the backflow dispersion index in the i-th period.

[0055] If the flowback dispersion index is greater than 1 and the larger it is, it indicates that the flowback flow fluctuation in the i-th cycle is significantly higher than the injection flow fluctuation. This suggests an abnormal disturbance or leakage channel exists during fluid transport within the well, increasing the likelihood of well leakage or fracture propagation. In this case, it is crucial to reduce the injection flow rate promptly to suppress further pressure increases and prevent the expansion of abnormal channels. If the flowback dispersion index is less than 1 and the smaller it is, it indicates a large injection flow fluctuation. The squeezing pressure's ability to maintain the injection flow is insufficient, and the squeezing pressure may be approaching its limit, posing a risk of adjustment failure. In this case, it is also necessary to appropriately reduce the injection flow rate to avoid continued pressure accumulation leading to instability. The closer the flowback dispersion index is to 1, the more it indicates that the flowback flow is mainly driven by the injection flow, the more stable the overall injection-displacement process is, and the greater the likelihood that the current injection-displacement flow rate is appropriate.

[0056] It should be noted that in the calculation of the back-row dispersion index, when the denominator is 0, the denominator is set to 0. , The preset parameter is used to avoid the denominator being 0. Its value range is (0.05, 0.1). The value has little impact on the calculation and can be ignored. In this embodiment, it is 0.08.

[0057] Furthermore, as cement slurry is continuously injected, the volume of fluid at the bottom of the well continues to accumulate, the flow resistance gradually increases, and the bottom pressure shows a slow upward trend. However, when the injection flow rate is too large, it will cause the bottom pressure to rise rapidly and gradually approach the formation pressure limit. When the bottom pressure exceeds the pressure limit and well leakage or fractures occur, some fluid will enter the formation, thereby reducing the rise in bottom pressure and possibly even causing a phased decline.

[0058] The bottom hole pressure sequence of the i-th period is used as the input of the sequence segmentation algorithm to segment it into multiple pressure subsequences. Based on the position range corresponding to each pressure subsequence, the injection flow sequence of the i-th period is synchronously divided into multiple corresponding injection flow subsequences to achieve time alignment between bottom hole pressure changes and injection behavior.

[0059] Sequence segmentation algorithms are not limited to BG segmentation or MK segmentation; this embodiment uses the BG sequence segmentation algorithm. The minimum segmentation length of the BG segmentation algorithm is set to 10 data points, the significance level is 0.95, and the optimal lag order is obtained through the autocorrelation function.

[0060] The mean values ​​of each pressure subsequence and each injection flow subsequence are calculated separately. For each mean value of the pressure subsequence and each injection flow subsequence within the i-th period, maximum value normalization is performed to eliminate the influence of dimensions. The maximum value is determined based on the corresponding parameter set of all pressure subsequences and all injection flow subsequences within the i-th period and the preceding N (10 in this embodiment) periods. If there are fewer than N periods preceding the i-th period, the normalized value is calculated based on the actual existing periods.

[0061] It should be noted that if the mean of all injection flow subsequences in each period is consistent, then the normalized value of the mean of each injection flow subsequence is set to 1; the mean of each pressure subsequence cannot be consistent.

[0062] Taking the u-th pressure subsequence as an example, the ratio between the normalized value of the mean of the u-th pressure subsequence and the normalized value of the mean of the corresponding injection flow rate subsequence is denoted as the calibration pressure value of the u-th pressure subsequence. By normalizing the mean, the influence of injection flow rate differences on bottom hole pressure changes can be effectively eliminated, avoiding calculation errors caused by fluctuations in injection flow rate. The calibration pressure value is used to characterize the corrected bottom hole pressure within the time period of the u-th pressure subsequence. The larger the calibration pressure value, the greater the bottom hole pressure within the time period of the u-th pressure subsequence.

[0063] Similarly, calculate the calibration pressure values ​​for all pressure subsequences. Arrange the calibration pressure values ​​of each pressure subsequence in the i-th period in chronological order to construct the calibration pressure value sequence for the i-th period. Obtain the number of negative numbers in the first-order difference sequence of the calibration pressure value sequence. The ratio of the number of negative numbers to the total length of the first-order difference sequence data is denoted as the anomaly ratio for the i-th period. The anomaly ratio reflects the proportion of the bottom hole pressure attenuation frequency during the injection process. The larger the value, the more likely it is that the bottom hole pressure has failed to rise multiple times with the continuous injection of cement slurry, indicating a greater possibility of well leakage or fracture propagation.

[0064] It should be noted that if the number of pressure subsequences after each period is less than 2, it indicates that the bottom hole pressure is rising normally and there is no abnormality. In this case, the abnormality ratio of each period is set to 0.

[0065] As a preferred implementation, based on the difference in dispersion between the backflow flow rate and the actual injection flow rate within each cycle, and the proportion of attenuation times of the corrected bottomhole pressure data in all trend changes for each cycle, an injection displacement risk index for each cycle is constructed to characterize the degree of risk in the cement slurry injection displacement process within each cycle. The method for constructing the injection displacement risk index for each cycle is as follows: The ratio between the variance of the backflow flow rate data and the variance of the actual injection flow rate data for each cycle is calculated, and the absolute difference between this ratio and 1 is calculated; the calibrated pressure values ​​of all pressure subsequences within each cycle are arranged in chronological order to obtain the calibrated pressure value sequence for each cycle; the ratio between the number of negative numbers in the first-order difference sequence of the calibrated pressure value sequence and the total length of the first-order difference sequence data is recorded as the anomaly ratio for each cycle; the injection displacement risk index for each cycle is positively correlated with both the absolute difference and the anomaly ratio. The positive correlation means that the dependent variable increases (decreases) as the independent variable increases (decreases).

[0066] In this embodiment, the injection / substitution risk index for the i-th period is denoted as... Its specific expression is: In the formula, Let be the injection risk index for the i-th period; Let be the backflow dispersion index for the i-th period; The abnormal proportion in the i-th period; For the normalization function, this embodiment uses the minimum-maximum normalization method. The minimum and maximum values ​​are taken based on a fixed extreme value range set by the corresponding parameters under absolute physical boundaries. The absolute physical boundaries refer to the value boundaries of the corresponding parameters under no-risk and maximum-risk conditions. Dividing by 2 is to make... The range of its value is [0,1].

[0067] The injection displacement risk index reflects the degree of risk that may exist in the cement slurry injection displacement process during the current cycle. The larger the value, the more unstable the flow state of the cement slurry during the current injection displacement process, and the greater the risk of well leakage, fracture expansion or abnormal leakage. This also reflects that the current injection flow rate is large and it is necessary to slow down the injection flow rate to reduce the squeezing pressure.

[0068] Step 3: Based on the difference between the maximum squeezing pressure and the preset formation ultimate pressure in each cycle, and the relative fluctuation of the squeezing pressure data, construct the pressure instability index for each cycle.

[0069] Furthermore, during the injection process, the bottom hole pressure is constantly changing, and therefore the flow resistance of the cement slurry also changes continuously. When the bottom hole pressure is low, a relatively small injection pressure is sufficient to maintain a stable injection flow rate. However, as the bottom hole pressure gradually increases and approaches the upper pressure limit, the flow resistance of the cement slurry also increases significantly, and the injection pressure required to maintain a stable injection flow rate will become increasingly larger.

[0070] If there is no well leakage or formation fracturing in the well, but the adjustment range of the squeezing pressure has been significantly increased and is close to the limit pressure that the formation can withstand in order to maintain a stable injection flow rate, although the injection displacement process does not show significant instability and the injection displacement risk index is small, the actual adjustment margin will shrink significantly at this time. The injection flow rate should be appropriately reduced to avoid instability caused by subsequent operating condition disturbances.

[0071] Let's take the i-th cycle as an example for analysis. The ratio of the maximum value in the injection pressure sequence within the i-th cycle to the preset formation limit pressure (in this embodiment, the preset formation limit pressure is 10 MPa) is denoted as the injection pressure risk level for the i-th cycle. The injection pressure risk level reflects how close the current injection pressure is to the wellhead pressure limit; the closer its value is to 1, the closer the current cycle's injection pressure is to the limit condition. If the original injection flow rate is maintained at this point, once the bottom hole pressure or flow resistance fluctuates, the injection pressure will lack room for further upward adjustment, making it difficult to effectively support the flow rate, which may lead to instability in the overall injection process and generate greater risks. It should be noted that the maximum value of the injection pressure risk level is 1.

[0072] Furthermore, the mean of the absolute differences between all adjacent elements in the injection pressure sequence of the i-th period is denoted as the injection fluctuation value of the i-th period. The injection fluctuation value reflects the average change in injection pressure; the larger the value, the greater the adjustment range of injection pressure in the i-th period.

[0073] The ratio between the squeezing fluctuation value of the i-th period and the mean of the squeezing pressure sequence is denoted as the relative fluctuation coefficient of the i-th period. The relative fluctuation coefficient reflects the relative intensity of the squeezing pressure change at the current pressure level, thereby eliminating the influence of the difference in the base value of squeezing pressure under different operating conditions. The larger the value, the more significant the increase in squeezing pressure required to maintain the injection flow rate. Continuing to maintain the original injection flow rate will lead to a rapid accumulation of squeezing pressure, which will not only aggravate the disturbance to the formation, but also further compress the adjustment space.

[0074] As a preferred embodiment, a pressure-holding instability index for each cycle is constructed based on the difference between the maximum value of the injection pressure in each cycle and the preset formation ultimate pressure, as well as the relative fluctuation of the injection pressure data. This index is used to characterize the risk of limited injection pressure regulation within each cycle. The method for constructing the pressure-holding instability index for each cycle is as follows: the ratio of the maximum value of the injection pressure data in each cycle to the preset formation ultimate pressure is calculated; the relative fluctuation coefficient for each cycle is obtained; the pressure-holding instability index for each cycle is positively correlated with both the ratio and the relative fluctuation coefficient.

[0075] In this embodiment, the pressure stagnation and instability index of the i-th period is denoted as... Its specific expression is: In the formula, Let be the pressure stagnation and instability index for the i-th period; The squeezing pressure risk level for the i-th cycle; Let be the relative fluctuation coefficient for the i-th period; As a normalization function, this embodiment uses the minimum-maximum normalization method for normalization, and the minimum and maximum values ​​are taken based on a fixed extreme value range set under the absolute physical boundary.

[0076] pass To reflect the remaining space between the injection pressure and the upper limit of the pressure bearing capacity; through This reflects the magnitude of pressure adjustment required to maintain the injection flow rate. The pressure instability index indicates the risk of limited pressure adjustment in the current cycle; the larger the value, the more rapidly the pressure required to maintain the injection flow rate in the current cycle has approached the formation's pressure limit, and the adjustment magnitude continues to increase. Continuing to maintain the original flow rate is more likely to cause instability or pumping limitation, requiring a reduction in the injection flow rate.

[0077] Step 4: Based on the difference between the total cement grout injection volume up to the end of each cycle and the preset total cement grout volume, construct the grouting schedule for each cycle, and combine the grouting risk index and pressure instability index for each cycle to construct the adjustment range for each cycle; based on the adjustment range of the current cycle and the actual injection flow rate, adjust the injection flow rate parameters of the grouting pump in the next cycle.

[0078] Furthermore, considering that both the injection-displacement risk index and the pressure buildup instability index can only analyze the degree of instability within a single cycle and do not incorporate the overall characteristics of the sand-fixing operation, a high injection-displacement risk index in the early stages of injection usually indicates that well leakage or fracture propagation may have occurred during the injection process. In this case, excessively high flow rates will exacerbate the expansion of abnormal channels, and the injection flow rate should be promptly reduced to suppress risk expansion. However, in the later stages of injection-displacement, as the drilling fluid is largely replaced by cement slurry and the annulus gradually fills, the increase in bottom hole pressure is a normal pressure buildup process. Fluctuations in flowback flow rate and pressure are more due to space constraints than abnormal leakage, thus requiring further analysis.

[0079] The product of the actual injection flow rate at each sampling time and the time interval between adjacent sampling times is recorded as the cement slurry injection volume at each sampling time. Then, the cumulative sum of the cement slurry injection volumes at all sampling times from the start of data collection until the end of the i-th cycle is calculated to obtain the total cement slurry injection volume up to the end of the i-th cycle.

[0080] The total amount of cement slurry injected up to the end of the i-th cycle is combined with the preset total amount of cement slurry to be injected during this replacement process (8 in this embodiment). The ratio of the two values ​​is denoted as the injection and replacement progress of the i-th cycle. The injection and replacement progress reflects the injection and replacement operation stage of the current cycle. The larger the value, the greater the possibility that the i-th cycle is the end of the injection and replacement process. At this time, the space inside the well has been gradually occupied by cement slurry, and the cement slurry is mainly in the state of filling and compaction. At this time, even if the injection and replacement risk index is large, it is more likely to be caused by normal pressure buildup rather than abnormal instability.

[0081] It should be noted that the total injection volume cannot exceed the preset total amount of cement slurry, therefore the maximum value of the injection progress in this application is 1.

[0082] Furthermore, the injection flow rate parameters of the grouting pump in the next cycle are adjusted as follows:

[0083] Considering that during the final stage of injection and displacement, the rise in bottom hole pressure is a normal pressure build-up process as the downhole space is gradually occupied by cement slurry, it may have an impact on... The calculation results are interfered with, therefore the injection progress of the i-th cycle is used to... and Perform weighted fusion to calculate the adjustment magnitude in the i-th cycle. The specific calculation formula is as follows: In the formula, Let be the adjustment range for the i-th cycle; The injection / replacement progress for the i-th cycle; Let be the injection risk index for the i-th period; Let be the pressure instability index for the i-th period.

[0084] Based on the injection flow rate and adjustment range of the current cycle, the injection flow rate parameters of the grouting pump are adjusted for the next cycle. The specific adjustment formula is as follows: In the formula, The injection flow rate parameter of the grouting pump in the (i+1)th cycle; A preset minimum injection flow rate is used to provide a lower limit constraint during flow rate reduction, preventing insufficient annular flow capacity or obstructed cement slurry propagation due to excessively low injection flow rate, which would affect the normal replacement process. In this embodiment, a flow rate of 0.2 is used. ; The average value of the actual injected flow data in the i-th period; Let be the adjustment range for the i-th cycle; This is a preset adjustment factor used to control the adjustment range within a single cycle, avoiding excessively rapid adjustment that could amplify system fluctuations. In this embodiment, it is set to 4. This is the function for finding the maximum value.

[0085] By using the above methods, the injection flow rate is reduced when the risk increases, and the lower limit constraint is used to prevent the flow rate from continuously decreasing. This ensures the continuity and effectiveness of the injection and replacement process while suppressing well leakage or fracture expansion, thereby achieving stable sealing and precise control of the sand and rock expulsion area.

[0086] It should be noted that: it has already passed This ensures a lower limit for the injected flow, thus preventing the injection flow regulation logic from going out of control.

[0087] During deep sealing, as wellbore space becomes increasingly limited and bottomhole pressure continues to accumulate, the characteristics of restricted injection become more pronounced. Therefore, the aforementioned injection flow rate adjustment method is also employed during deep sealing to dynamically correct the injection flow rate parameters of the grouting pump in each cycle. This allows the injection flow rate to adaptively adjust with changes in downhole pressure and flow resistance, thereby avoiding local instability or insufficient sealing caused by improper injection flow rate control during the deep sealing stage, and further improving the overall sealing quality and wellbore stability.

[0088] Similarly, the injection flow rate parameters of the grouting pump are adaptively adjusted during the shallow and deep sealing processes of sand-fixing wellbore #2 and sand-fixing wellbore #3.

[0089] By dynamically adjusting the injection flow rate parameters of the grouting pump using the above method, the risks of abnormal leakage and restricted injection are reduced, thereby improving the stability of the sealing process and construction safety.

Claims

1. A method for precise sealing of areas in wells that produce sand and rock through misalignment, characterized in that, The method includes the following steps: The location of each sand-stabilizing well is determined based on the original wellbore location; the bottom hole pressure, actual injection flow rate, squeezing pressure, and backflow flow rate of each sand-stabilizing well are acquired in real time during the sealing process; The bottom hole pressure data is corrected by using the actual injection flow rate data of each sand-fixing well in each cycle. Based on the difference between the dispersion of the backflow flow rate and the actual injection flow rate in each cycle, and the proportion of the decay times of the corrected bottom hole pressure data in all trend changes, the injection displacement risk index of each cycle is constructed. Based on the difference between the maximum squeezing pressure and the preset formation ultimate pressure in each cycle, as well as the relative fluctuation of the squeezing pressure data, a pressure stagnation and instability index for each cycle is constructed. Based on the difference between the total cement grout injection volume up to the end of each cycle and the preset total cement grout volume, the grouting schedule for each cycle is constructed. Combined with the grouting risk index and pressure instability index for each cycle, the adjustment range for each cycle is constructed. Based on the adjustment range of the current cycle and the actual injection flow rate, the injection flow rate parameter of the grouting pump in the next cycle is adjusted. The location of each sand-fixing wellbore refers to the location of three sand-fixing wellbores evenly distributed at a central angle of 120° on a circle with the original wellbore as the center and a preset radius as the radius.

2. The method for precise sealing of a faulted well area that produces sand and rock as described in claim 1, characterized in that, The specific process of correcting the bottom hole pressure data using the actual injection flow rate data of each sand-fixing wellbore in each cycle is as follows: The sequence of bottom hole pressure data from each period, arranged in chronological order, is used as input to a sequence segmentation algorithm to obtain multiple pressure subsequences. Based on the position range corresponding to each pressure subsequence, the actual injection flow data of the same period is synchronously divided into multiple corresponding injection flow subsequences; The ratio between the normalized value of the mean of each pressure subsequence and the normalized value of the mean of the corresponding injection flow subsequence is recorded as the calibration pressure value of each pressure subsequence, thereby completing the correction of the bottom hole pressure data.

3. The method for precise sealing of a faulted well area that produces sand and rock as described in claim 2, characterized in that, The method for constructing the injection and substitution risk index for each period is as follows: The ratio between the variance of the backflow flow data and the variance of the actual injection flow data for each period is calculated, and the absolute difference between this ratio and 1 is calculated. The calibration pressure values ​​of all pressure subsequences in each period are arranged in chronological order to obtain the calibration pressure value sequence for each period. The ratio between the number of negative numbers in the first-order difference sequence of the calibration pressure value sequence and the total length of the first-order difference sequence data is recorded as the anomaly ratio for each period. The injection risk index for each period is positively correlated with the absolute difference and the abnormality ratio.

4. The method for precise sealing of a well area with staggered sand and rock discharge as described in claim 1, characterized in that, The method for constructing the pressure buildup and instability index for each cycle is as follows: The ratio of the maximum value of the injection pressure data in each cycle to the preset formation ultimate pressure is calculated. Based on the relative fluctuation of the injection pressure data in each period, a relative fluctuation coefficient for each period is constructed. The pressure instability index for each period is positively correlated with the ratio and the relative volatility coefficient.

5. The method for precise sealing of a well area with staggered sand and rock discharge as described in claim 4, characterized in that, The method for constructing the relative volatility coefficients for each period is as follows: The mean of the absolute differences between all adjacent elements in the sequence of squeezing pressure data for each period, arranged in chronological order, is calculated and denoted as the squeezing fluctuation value for each period. The average value of all injection pressure data for each period is calculated. The ratio of the squeezing fluctuation value to the mean value is recorded as the relative fluctuation coefficient for each period.

6. The method for precise sealing of a faulted well area that produces sand and rock as described in claim 1, characterized in that, The replacement progress of each cycle refers to the ratio between the total amount of cement slurry injected up to the end of each cycle and the preset total amount of cement slurry to be injected during this replacement process.

7. The method for precise sealing of a well area with staggered sand and rock discharge as described in claim 1, characterized in that, The method for obtaining the total cement slurry injection volume up to the end of each cycle is as follows: The product of the actual injection flow rate at each sampling time and the time interval between adjacent sampling times is recorded as the cement slurry injection volume at each sampling time. The total cement slurry injection volume is calculated by summing the cement slurry injection volume at all sampling times from the start of data acquisition until the end of each cycle.

8. The method for precise sealing of a well area with staggered sand and rock discharge as described in claim 1, characterized in that, The formula for calculating the adjustment range of each cycle is as follows: In the formula, Let be the adjustment range for the i-th cycle; The injection / replacement progress for the i-th cycle; Let be the injection risk index for the i-th period; Let be the pressure instability index for the i-th period.

9. A method for precise sealing of a faulted well area that produces sand and rock as described in claim 1, characterized in that, The specific formula for adjusting the injection flow rate parameter of the grouting pump in the next cycle is as follows: In the formula, The injection flow rate parameter of the grouting pump in the (i+1)th cycle; Set the minimum injection flow rate; The average value of the actual injected flow data in the i-th period; Let be the adjustment range for the i-th cycle; This is a preset adjustment factor; This is the function for finding the maximum value.

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