Drilling fluid optimization control method based on high-pressure abnormal formation pressure prediction

Abstract

The invention discloses a drilling fluid optimization control method based on high-pressure abnormal formation pressure prediction, and relates to the technical field of drilling automatic control, and the method comprises the steps: 1, building a pressure abnormal coefficient model of a target formation according to geological characteristic parameters of the target formation, and calculating a pressure abnormal coefficient for evaluating the degree that the actual formation pressure deviates from the normal pressure; wherein the target stratum is a high-pressure abnormal stratum, and the actual stratum pressure of the target stratum is higher than a set pressure threshold value; 2, according to the pressure abnormal coefficient, the optimal drilling fluid density is calculated, and the stability of the well wall is ensured while the formation pressure is balanced; and 3, setting an underground pressure constraint relation, and adjusting the underground flow and the well outlet flow in real time in a linkage manner through a dynamic control model. The density and flow of the drilling fluid can be dynamically adjusted, it is ensured that the underground pressure is always kept within the safety range, and safety accidents such as well wall breakage or blowout are avoided.

Description

Technical Field

[0001] The invention relates to the technical field of automatic drilling control, and in particular to a drilling fluid optimization control method based on prediction of high-pressure abnormal formation pressure. Background Art

[0002] As an indispensable part of the oil and gas drilling process, drilling fluid is mainly used to balance downhole pressure, cool the drill bit, remove drill cuttings, and prevent wellbore collapse. The main goal of traditional drilling fluid is to control downhole pressure and keep it in balance with formation pressure, thereby ensuring the stability and safety of the drilling process. However, with the continuous increase in drilling depth and the complexity of formation conditions, especially the emergence of abnormal high-pressure formations, traditional drilling fluid optimization control methods are facing more and more challenges.

[0003] In the existing drilling fluid optimization control technology, the density of the drilling fluid is generally set according to the downhole formation pressure. The downhole formation pressure mainly includes hydrostatic pressure and rock pressure. The hydrostatic pressure is the pressure generated by the deadweight of the drilling fluid, and the rock pressure is the pressure generated by the gravity of the formation rock. In theory, the density of the drilling fluid should be large enough to resist the formation pressure and prevent safety accidents such as well wall collapse or blowout. However, traditional control methods mostly rely on static parameter settings and do not fully consider the real-time changes in formation pressure and the complex situations brought about by abnormal high-pressure formations.

[0004] As the drilling depth increases, the volatility of downhole pressure becomes greater. Especially in abnormally high-pressure formations, the actual pressure of the formation is much higher than the pressure under normal conditions. This pressure change is usually unpredictable and has a large uncertainty. Traditional drilling fluid optimization control methods often use hydrostatic pressure or rock pressure as reference values, while ignoring the pressure anomalies that may occur in the formation under different conditions. For this reason, a common practice is to choose a higher density when designing the drilling fluid to ensure that the downhole pressure can be balanced when the pressure fluctuates greatly. However, this method cannot accurately control the downhole pressure, which can easily lead to excessive density of the drilling fluid, thereby increasing the stress on the wellbore, causing wellbore instability or excessive consumption of drilling fluid. Summary of the invention

[0005] In order to solve the above technical problems, a drilling fluid optimization control method based on high-pressure abnormal formation pressure prediction is provided.

[0006] In order to achieve the above purpose, the technical solution adopted by the present invention is: The drilling fluid optimization control method based on the prediction of abnormal high-pressure formation pressure includes: Step 1: According to the geological characteristic parameters of the target formation, a pressure anomaly coefficient model of the target formation is established, and the pressure anomaly coefficient is calculated to evaluate the degree to which the actual formation pressure deviates from the normal pressure; wherein the target formation is a high-pressure abnormal formation, and its actual formation pressure is higher than the set pressure threshold; Step 2: Calculate the optimal drilling fluid density based on the pressure anomaly coefficient to balance the formation pressure while ensuring wellbore stability; Step 3: According to the time change rate of bottom hole pressure, a dynamic control model for coupling the inflow and outflow of downhole pressure drilling fluid under the optimal drilling fluid density is established; the downhole pressure constraint relationship is set, and the downhole flow rate and outflow flow rate are adjusted in real time through the dynamic control model.

[0007] Furthermore, geological characteristic parameters include: actual formation pressure , unit is MPa; hydrostatic pressure , unit is MPa; formation porosity ; Stratigraphic depth , the unit is ; Formation compaction coefficient , which indicates the degree of change of formation porosity with depth in the target formation, obtained through experimental calibration; rock pressure , unit is MPa; formation pore pressure , unit is MPa; formation fracture pressure , unit is MPa.

[0008] Furthermore, the pressure anomaly coefficient model is: ; in, is the pressure anomaly coefficient; The depth at which drilling fluid injection begins; The porosity of the formation corresponding to the depth at which drilling fluid injection begins.

[0009] Furthermore, the optimal drilling fluid density is calculated based on the pressure anomaly coefficient. : ; in, is the density of water, in kg / cm³; is the solid specific gravity of the rock and soil sample of the target stratum; is the compression index, in units of , obtained by obtaining rock and soil samples of the target stratum and then conducting triaxial tests on the rock and soil samples; It is the ratio of formation porosity to the volume of formation solid particles when the drilling fluid begins to be injected. is the effective stress, in MPa; is the acceleration due to gravity, which is a constant; is the safety pressure margin, in MPa; is the drilling fluid viscosity, in mPa·s; is the rheological index of drilling fluid; is the initial viscosity of the drilling fluid, in mPa·s; is the safety factor.

[0010] Furthermore, the safety factor is: .

[0011] Furthermore, the safety pressure margin for: .

[0012] Furthermore, the dynamic control model is: ; in, is the time variation function of the bottom hole pressure, which is obtained by measuring the bottom hole pressure value in a set time window in real time and constructing a pressure curve function; is the wellbore energy storage coefficient, which is the set value in m³ / MPa; for The inflow rate at time, in m³ / s; for The outflow rate at the time, in m³ / s; is the formation expansion volume, in m³; is the Darcy friction coefficient of drilling fluid flowing in the pipeline; is the borehole diameter, in m; The circulation flow rate of drilling fluid; is the equivalent well section length, in m; is the expansion volume normalization coefficient, which takes values ​​of 100, 200 or 300. The easier the formation is to expand, the higher the value; is the pressure anomaly coefficient.

[0013] Furthermore, the Darcy friction coefficient The calculation formula is: ; in, is the surface roughness of the pipeline; is the pipe diameter; is the Reynolds number.

[0014] Furthermore, the downhole pressure constraint relationship is: the bottom hole pressure is less than the formation fracture pressure 1.5 times of.

[0015] Compared with the prior art, the beneficial effect of the present invention is that the drilling fluid optimization control method of the present invention effectively solves the problem that the prior art cannot accurately respond to the pressure fluctuation of high-pressure abnormal formations by combining the pressure anomaly coefficient model, drilling fluid density adjustment and dynamic control system based on the prediction of high-pressure abnormal formation pressure. By real-time monitoring of parameters such as bottom hole pressure, flow rate, physical properties of the formation, etc., the present invention can dynamically adjust the density and flow rate of the drilling fluid to ensure that the downhole pressure is always kept within a safe range, avoiding the occurrence of safety accidents such as wellbore rupture or blowout. The advantage of this method is that it can respond to downhole pressure changes in real time, accurately adjust the drilling fluid flow rate, and significantly improve the safety and stability of drilling operations. Compared with the prior art, the present invention can adopt a more accurate control strategy according to the actual pressure changes of high-pressure abnormal formations, avoiding the excessively high or low drilling fluid density caused by the traditional static pressure estimation method, thereby reducing the consumption of drilling fluid and reducing the wellbore stress. BRIEF DESCRIPTION OF THE DRAWINGS

[0016] Figure 1 This is a schematic diagram of the method flow of the drilling fluid optimization control method based on high-pressure abnormal formation pressure prediction proposed by the present invention. DETAILED DESCRIPTION

[0017] The following description is used to disclose the present invention so that those skilled in the art can implement the present invention. The preferred embodiments described below are only examples, and those skilled in the art may think of other obvious variations.

[0018] Reference Figure 1 As shown, the drilling fluid optimization control method based on high-pressure abnormal formation pressure prediction in an embodiment of the present invention includes: Step 1: According to the geological characteristic parameters of the target formation, a pressure anomaly coefficient model of the target formation is established, and the pressure anomaly coefficient is calculated to evaluate the degree to which the actual formation pressure deviates from the normal pressure; wherein the target formation is a high-pressure abnormal formation, and its actual formation pressure is higher than the set pressure threshold; During the drilling process, the pressure of the formation is not static, but is closely related to the various geological characteristics of the formation. Normally, the formation pressure includes multiple factors such as hydrostatic pressure, rock and soil pressure, and pore water pressure, and the actual formation pressure is affected by geological conditions, especially in high-pressure abnormal formations, where the formation pressure often exceeds conventional design standards. In order to accurately assess the degree of abnormality of these pressures, the present invention introduces the concept of pressure anomaly coefficient, comprehensively considers multiple geological characteristic parameters such as porosity, lithology, and depth of the formation, and then calculates a quantitative parameter, namely the pressure anomaly coefficient. This coefficient reflects the degree of deviation of the actual formation pressure from the normal pressure, and provides basic data for subsequent drilling fluid optimization.

[0019] By establishing such a pressure anomaly coefficient model, drilling operators can accurately predict the pressure changes under different formation conditions, and thus provide a basis for adjusting the density of the drilling fluid. In high-pressure abnormal formations, too high or too low drilling fluid density may have an adverse effect on the wellbore. If the drilling fluid density is too low, it may not be able to effectively resist the formation pressure, resulting in wellbore collapse; if the density is too high, it may cause excessive stress on the wellbore, further exacerbating the damage to the wellbore. Therefore, understanding the abnormal degree of formation pressure and its changing trend is crucial to selecting the appropriate drilling fluid density.

[0020] The establishment of the pressure anomaly coefficient model does not rely solely on a single feature of the formation, but integrates multiple parameters. First, the difference between the actual pressure of the target formation and the hydrostatic pressure is the main factor determining the pressure anomaly. Hydrostatic pressure refers to the pressure generated by the liquid in a static state. It is directly related to the depth and density of the formation, while the actual formation pressure is affected by many factors, including the lithology, temperature, porosity, etc. of the formation. When the actual formation pressure is higher than the hydrostatic pressure, it means that the formation has abnormal pressure. Therefore, by calculating this pressure difference, it is possible to preliminarily assess whether the pressure of the formation deviates from the normal range.

[0021] Secondly, formation porosity plays a vital role in the formation of pressure anomalies. Porosity refers to the ratio of the pore volume in the rock to the total rock volume. It directly affects the storage capacity of water or gas in the formation, and thus affects the distribution of pressure. In high-pressure abnormal formations, the change in porosity is often related to the compaction degree of the formation. Therefore, the consideration of porosity in the pressure anomaly coefficient model can further accurately quantify the deviation of formation pressure.

[0022] In addition, the influence of formation depth on the pressure anomaly coefficient cannot be ignored. As the drilling depth increases, the formation pressure usually increases with the depth, and in deep formations, the formation mechanism of abnormal pressure will also be different. By introducing the depth parameter into the pressure anomaly coefficient model, the influence of deep geological conditions on pressure can be better reflected. Deeper formations are usually accompanied by greater pressure anomalies, so the role of depth in the model cannot be underestimated.

[0023] The pressure anomaly coefficient model of the present invention not only takes into account the above-mentioned physical parameters, but also combines the dynamic changes of the actual formation. For example, with the injection of drilling fluid, the porosity and pressure of the formation may change, and these dynamic changes also have a certain impact on the calculation of the pressure anomaly coefficient. Therefore, in the present invention, the pressure anomaly coefficient is not a static value, but is adjusted in real time according to the actual situation of the formation and the injection of drilling fluid. In this way, the optimization control method of drilling fluid can better adapt to the changes in formation pressure, thereby improving the safety and efficiency of drilling operations.

[0024] Step 2: Calculate the optimal drilling fluid density based on the pressure anomaly coefficient to balance the formation pressure while ensuring wellbore stability; In step one, the calculation of the pressure anomaly coefficient has provided a measure of the deviation of formation pressure from the normal range. This coefficient reflects the degree of abnormality of the formation pressure and takes into account multiple geological factors, such as porosity, lithology, formation depth, and effective stress. Therefore, the key task of step two is to calculate an optimal drilling fluid density based on this coefficient. This density must not only resist the high pressure from the formation, but also avoid the drilling fluid being too dense, thereby exerting excessive pressure on the wellbore wall. Excessive drilling fluid density may cause excessive stress on the wellbore wall, which in turn increases the risk of wellbore collapse. Therefore, the calculation of the optimal drilling fluid density must consider both pressure balance and safety protection for the wellbore wall.

[0025] The calculation method of the optimal drilling fluid density combines multiple influencing factors, the most important of which are the pressure anomaly coefficient and the geological characteristics of the formation. In high-pressure abnormal formations, the density of the drilling fluid must be large enough to ensure that it can effectively resist the pressure of the formation, but it cannot be too large, otherwise it will cause unnecessary safety hazards. For example, parameters such as the solid specific gravity, porosity, and compression index of the rock and soil samples of the formation will affect the optimal density of the drilling fluid. These geological characteristics reflect the physical properties of the formation, which in turn affects the performance of the drilling fluid in the formation. In this process, the density of the drilling fluid is not only a static physical quantity, it is also affected by dynamic factors, especially in a high-pressure environment, the fluidity and density regulation of the drilling fluid will change with the increase in depth and the change in formation characteristics.

[0026] In addition, the calculation of optimal density also requires the introduction of the concept of safety pressure margin. During the drilling process, the formation pressure often fluctuates unstably, and the drilling fluid needs to maintain a dynamic equilibrium state in these fluctuations. The introduction of safety pressure margin ensures that when the formation pressure fluctuates, the drilling fluid density can adapt to these changes, avoiding wellbore collapse or other potential risks caused by sudden pressure increases. By combining parameters such as formation depth, initial viscosity of drilling fluid and safety factor, the optimal density that adapts to the current environment can be calculated at each moment.

[0027] The calculation process of the optimal density involves not only static geological parameters, but also the rheological properties of the drilling fluid itself. The rheological index, viscosity, and fluidity of the drilling fluid will affect the flow of the drilling fluid in the pipeline, thereby indirectly affecting the pressure distribution downhole. Therefore, when calculating the optimal density, these rheological properties must be considered at the same time to ensure that the drilling fluid can maintain good fluidity throughout the drilling process and has sufficient pressure control capabilities. In high-pressure abnormal formations, the adjustment of the viscosity and rheological index of the drilling fluid can help optimize the pressure distribution downhole, so that the drilling fluid can remain stable under high-pressure conditions and avoid the problem of wellbore instability caused by poor flow or excessive viscosity.

[0028] In addition to the above parameters, the compression index also plays an important role in the calculation of the optimal density. The compression index reflects the compressibility of the formation rock and soil samples under the action of external pressure. In high-pressure abnormal formations, formations with a larger compression index require a higher drilling fluid density to resist the pressure. Therefore, by measuring the compressibility of the target formation rock and soil samples, the density of the drilling fluid can be accurately adjusted to achieve the optimal pressure balance effect.

[0029] Step 3: According to the time change rate of bottom hole pressure, a dynamic control model for coupling the inflow and outflow of downhole pressure drilling fluid under the optimal drilling fluid density is established; the downhole pressure constraint relationship is set, and the downhole flow rate and outflow flow rate are adjusted in real time through the dynamic control model.

[0030] In traditional drilling fluid control methods, the relationship between flow and pressure is usually set based on experience or static formulas, which makes it difficult to respond to changes in formation pressure in real time. The characteristics of drilling operations in high-pressure abnormal formations are that the formation pressure is very complex and usually fluctuates greatly. Especially in deep geological environments, pressure changes are often unpredictable, and traditional control methods cannot effectively cope with such dynamic changes. Therefore, the present invention establishes a dynamic control model, takes the real-time changes in bottom hole pressure as an important input of the model, and adjusts the flow rate in real time according to the pressure changes. The core of this method is to calculate an optimal flow control strategy by real-time monitoring of changes in bottom hole pressure and drilling fluid flow, so as to always keep the downhole pressure within a safe range.

[0031] The design of this dynamic control model is based on the analysis of multiple factors of the formation and drilling fluid, especially the complex coupling relationship between bottom hole pressure and the inflow and outflow of the well. With the injection of drilling fluid, the pressure downhole will change accordingly, and the change in bottom hole pressure directly affects the fluidity of the drilling fluid. Therefore, it is necessary to have a deep understanding of the dynamic laws of downhole pressure changes, and dynamically adjust the flow rate into and out of the well in combination with the current flow and density data. In the present invention, the model accurately calculates the rate of change of bottom hole pressure, monitors the dynamic changes of downhole pressure in real time, and then adjusts the flow rate in time according to the change trend to ensure that the pressure is always maintained within the ideal range.

[0032] In addition, the model also considers the interaction between the rheological properties of the drilling fluid and the formation properties. In abnormally high-pressure formations, the fluid properties such as the rheological index and viscosity of the drilling fluid will change with the change of pressure, resulting in changes in the resistance to the flow of the fluid downhole. These changes affect the pressure distribution and flow regulation downhole. Therefore, the control model must not only consider the direct relationship between flow and pressure, but also the dynamic characteristics of the fluid itself, and adjust the flow in real time to adapt to changes in formation pressure and drilling fluid properties.

[0033] In order to ensure the stability of the drilling process, the model also introduces a downhole pressure constraint relationship, that is, the bottom hole pressure must not exceed a certain multiple of the formation fracture pressure. Through this constraint relationship, accidents such as wellbore rupture can be effectively avoided. Specifically, the upper limit of the bottom hole pressure is set to 1.5 times the formation fracture pressure. This design ensures that even in the case of large pressure fluctuations, the flow and pressure control of the drilling fluid can still be maintained within a safe range, avoiding wellbore rupture caused by excessive pressure. Through this pressure safety mechanism, the present invention effectively improves the safety of drilling operations and reduces the risk of accidents.

[0034] Furthermore, this dynamic control model can not only handle static flow adjustment problems, but also cope with dynamic pressure changes. As the drilling depth increases, the pressure distribution of the formation and the flow behavior of the drilling fluid will change. Therefore, the model needs to calculate the appropriate flow adjustment scheme based on the real-time measured bottom hole pressure and other related parameters. Compared with the traditional static control method, this control method based on the pressure change rate has stronger adaptability and flexibility, and can respond to pressure changes in real time in complex formation environments and optimize the flow control of drilling fluid.

[0035] In addition, the real-time and high efficiency of the model also greatly improve the efficiency of drilling operations. In traditional drilling fluid control, flow adjustments are often required based on previous predictions and empirical data, and these adjustments cannot accurately adapt to fluctuations in formation pressure. The present invention can respond in the shortest time by monitoring the bottom hole pressure in real time and combining it with flow regulation, thereby greatly shortening the response time and ensuring the stability of the downhole pressure and the safety of the well wall.

[0036] Furthermore, geological characteristic parameters include: actual formation pressure , unit is MPa; hydrostatic pressure , unit is MPa; formation porosity ; Stratigraphic depth , unit is m; formation compaction coefficient , which indicates the degree of change of formation porosity with depth in the target formation, obtained through experimental calibration; rock pressure , unit is MPa; formation pore pressure , unit is MPa; formation fracture pressure , unit is MPa.

[0037] Actual formation pressure ( ) refers to the actual formation pressure measured during the drilling process, which directly determines the density of the drilling fluid required for downhole operations. Formation pressure is usually affected by many factors, such as the depth of the formation, porosity, and the properties of the rock. Therefore, the actual formation pressure is not only the basis for downhole pressure control, but also one of the key parameters in the calculation of drilling fluid density. In abnormally high-pressure formations, It is usually significantly higher than the conventional formation pressure, so it is crucial to understand the size of this pressure. Only by accurately obtaining this data can we ensure that the calculation of drilling fluid density can effectively balance the formation pressure and prevent safety issues such as well wall collapse or blowout.

[0038] Hydrostatic pressure ( ) is the pressure generated by the deadweight of the drilling fluid at the depth of the formation. It is an important reference value in conventional formation pressure estimation. The calculation of hydrostatic pressure is relatively simple and is inferred from parameters such as formation depth, drilling fluid density and gravity acceleration. Compared with the actual formation pressure, hydrostatic pressure is usually lower and represents the pressure of the drilling fluid when it is stationary. In the optimization control of drilling fluid, hydrostatic pressure is used as a reference pressure to help evaluate the pressure changes in the formation and determine whether the downhole pressure exceeds the normal range. Since hydrostatic pressure is determined by the density of the drilling fluid and the depth of the formation, it also affects the calculation of the optimal density.

[0039] Formation porosity ( ) refers to the ratio of the pore volume in the rock to the total volume of the rock. Porosity is an important parameter that describes the ability of rocks to store fluids (such as oil, gas, water, etc.). During the drilling process, it directly affects the distribution of formation pressure. Changes in porosity affect the storage capacity of water or gas in the formation, which in turn affects the formation of pore pressure. Porosity usually changes with increasing depth of the formation. In deep formations, porosity is usually lower, so detailed measurement and monitoring of this parameter is required to help calculate the density of the drilling fluid and optimize control.

[0040] Depth of formation ( ) is one of the basic parameters that affect the calculation of formation pressure and drilling fluid density. As the drilling depth increases, the formation pressure usually increases. The greater the depth, the higher the formation pressure, which plays a decisive role in the calculation of the optimal density. The change in formation depth during drilling is an important factor in the change of pressure and temperature. Therefore, accurate measurement and calculation of formation depth is essential for real-time adjustment of drilling fluid density.

[0041] Formation compaction coefficient ( ) describes the degree to which the porosity of a formation changes with depth. After a formation is compacted for a long time, its porosity will gradually decrease, and the formation pressure will increase accordingly. The compaction coefficient is obtained through experimental calibration. It reflects the relationship between the change in formation porosity and depth, and affects the fluid storage capacity and pressure distribution in the formation. In high-pressure abnormal formations, the change in the compaction coefficient is of great significance to the prediction of formation pressure, especially in the optimization calculation of drilling fluid density, the effect of this parameter on pressure anomaly needs to be considered.

[0042] Rock pressure ( ) is the pressure generated by the weight of the rock in the formation, which usually increases with depth. Rock pressure is closely related to the physical properties of the formation. It works together with hydrostatic pressure to determine the total pressure of the formation. In drilling fluid optimization control, rock pressure provides a basis for evaluating the upper limit of formation pressure. The calculation of rock pressure is an important part of formation pressure analysis, especially in high-pressure abnormal formations, where changes in rock pressure have a key impact on the adjustment of optimal density.

[0043] Formation pore pressure ( ) refers to the pressure generated by the fluid in the pores of the formation. It is usually the pressure caused by the fluid in the pores (such as water or gas) and is closely related to the porosity and lithology of the formation. Pore pressure is an important component of formation pressure. Understanding pore pressure helps predict the fluctuation of downhole pressure and its impact on drilling fluid density. In high-pressure abnormal formations, changes in formation pore pressure are usually one of the main reasons for abnormal formation pressure. Therefore, when calculating the optimal drilling fluid density, the influence of formation pore pressure must be considered.

[0044] Formation fracture pressure ( ) refers to the minimum pressure value at which the formation may rupture during the drilling process. If this pressure value is exceeded, the formation will rupture, resulting in instability of the wellbore. The formation rupture pressure is usually closely related to factors such as the lithology, porosity and compaction degree of the formation. In order to ensure safety during the drilling process, the downhole pressure must be kept below the formation rupture pressure. The calculation of the optimal drilling fluid density needs to take this parameter into account to avoid overpressure causing formation rupture.

[0045] Furthermore, the pressure anomaly coefficient model is: ; in, is the pressure anomaly coefficient; The depth at which drilling fluid injection begins; The porosity of the formation corresponding to the depth at which drilling fluid injection begins.

[0046] Specifically, the first part of the model is to compare the difference between the actual formation pressure and the hydrostatic pressure, i.e. . Actual formation pressure ( ) is the pressure measured in real time during drilling, which is usually higher than the hydrostatic pressure ( ) is higher because the actual formation pressure is affected by the underground rock formation and its fluids, and often exceeds the hydrostatic pressure. The hydrostatic pressure is the pressure generated by the gravity of the drilling fluid itself, which is usually relatively fixed and can be calculated from the known liquid density and drilling depth. In high-pressure abnormal formations, the deviation of the actual formation pressure from the hydrostatic pressure will increase significantly, and this difference is the manifestation of abnormal formation pressure. Therefore, by calculating this difference, preliminary information on abnormal formation pressure can be reflected.

[0047] The second part of the model takes into account the difference between rock pressure and hydrostatic pressure, i.e. . Rock pressure ( ) is the pressure generated by the deadweight of the formation rock, which increases with the depth of the wellbore. Rock pressure is usually higher than hydrostatic pressure and plays a decisive role in the overall pressure of the formation. By calculating the difference between rock pressure and hydrostatic pressure, an approximate upper limit for the formation pressure can be obtained. Therefore, this term plays a normalizing role in the model and is used to relate the calculation of the pressure anomaly coefficient to the lithology of the formation.

[0048] The key to the pressure anomaly coefficient model lies in its exponential part, namely This term takes into account the effect of formation porosity changes on pressure anomalies. Porosity ( ) refers to the pore ratio in the rock, which directly affects the storage and flow capacity of fluids in the formation. The injection of drilling fluid will cause changes in porosity, especially in deep formations, where changes in porosity will significantly affect the pressure state of the formation. Through this formula, we can capture the changes in porosity with the depth of drilling ( ) increases, and the impact of changes in formation porosity on formation pressure anomalies.

[0049] It is the porosity when the drilling fluid begins to be injected, which reflects the impact of the drilling fluid on the formation porosity in the initial stage of injection. It is the depth at which drilling fluid begins to be injected, marking the beginning of the drilling operation. During the drilling process, the porosity of the formation usually changes with increasing depth, and the porosity of deep formations is lower than that of shallow formations. It is the compaction coefficient of the formation, which indicates the degree of change of formation porosity with depth, and is usually obtained through experimental calibration. The compaction coefficient reflects the degree of compression of formation porosity under pressure. Therefore, by calculating this index term, it is possible to describe the relationship between porosity change and depth, and then quantify the abnormal degree of formation pressure.

[0050] Furthermore, the optimal drilling fluid density is calculated based on the pressure anomaly coefficient. : ; in, is the density of water, in kg / cm³; is the solid specific gravity of the rock and soil sample of the target stratum; is the compression index, in units of , obtained by obtaining rock and soil samples of the target stratum and then conducting triaxial tests on the rock and soil samples; It is the ratio of formation porosity to the volume of formation solid particles when the drilling fluid begins to be injected. is the effective stress, in MPa; is the acceleration due to gravity, which is a constant; is the safety pressure margin, in MPa; is the drilling fluid viscosity, in mPa·s; is the rheological index of drilling fluid; is the initial viscosity of the drilling fluid, in mPa·s; is the safety factor.

[0051] In the present invention, the optimal drilling fluid density ( ) is a key step in drilling operations in abnormally high-pressure formations. Its purpose is to avoid blowouts and other potential safety risks while ensuring wellbore stability and formation pressure balance through precise density adjustment. The calculation of this density depends on multiple geological characteristics and drilling fluid rheological properties. By comprehensively considering factors such as the compaction of the formation, porosity, lithology, and rheological index of the drilling fluid, an optimal density that adapts to specific formation pressure conditions is obtained.

[0052] First, the formula Represents the density of water in units of As a basic component of drilling fluid, the density of water is usually used as a benchmark value for calculating the density of drilling fluid. Drilling fluid is usually composed of water and other components (such as bentonite, weighting agent, etc.), so the density of water provides a basic unit of measurement for other components. By correcting the density of water, the final drilling fluid density can be calculated to maintain sufficient support in high-pressure formations.

[0053] Next, the formula This part is based on the pressure anomaly coefficient ( ) to correct the drilling fluid density. Pressure anomaly coefficient The degree of formation pressure anomaly is assessed by comparing the difference between actual formation pressure and hydrostatic pressure. In high-pressure abnormal formations, the actual formation pressure often exceeds the preset pressure threshold, so It can reflect the abnormal degree of formation pressure. A larger value indicates that the pressure anomaly is more serious and the drilling fluid needs to have a higher density to resist this abnormal pressure. It is the solid specific gravity of the target formation rock sample. This parameter describes the physical density of the formation rock and is the basis for understanding the formation pressure state. The solid specific gravity of the rock will mostly vary with the formation type. The solid specific gravity of different rock formations such as sandstone, shale, limestone, etc. is different, which will directly affect the formulation of the drilling fluid. This parameter can be determined through field sampling and experimental data. It is the ratio of the formation porosity to the volume of solid particles when the drilling fluid begins to be injected. It reflects the impact of drilling fluid injection on the formation porosity. The porosity of the formation usually decreases with increasing depth, affecting the fluid storage and transmission capacity of the formation. It is a compression index, which is calibrated on formation rock and soil samples through triaxial tests, reflecting the compressibility of rock and soil under pressure. The compression index affects the pressure response of drilling fluid in the formation. The greater the compressibility, the stronger the effective compression force of the formation. Accordingly, the density of the drilling fluid needs to be adjusted to maintain balance. It is the effective stress of the formation, which indicates the resistance of the rock formation to external pressure. The effective stress is the result of the interaction between the formation pore water pressure and the rock strength, which determines the compression behavior of the rock formation during the drilling process.

[0054] Part 2 It involves the safety pressure margin of drilling fluid. It is the safety pressure margin, which takes into account the possible fluctuations in formation pressure during drilling and the additional pressure required to ensure the stability of the wellbore. The introduction of the safety pressure margin allows the drilling fluid density to cope with abnormal formation pressure while leaving enough safety space to avoid wellbore collapse due to low pressure. is the acceleration due to gravity, in units of , which is a constant used to calculate the pressure change of drilling fluid at the depth of the formation. The greater the drilling depth, the higher the formation pressure is usually, and the density of the drilling fluid needs to be increased accordingly. It is a safety factor that reflects the bearing capacity of the formation and the buffering capacity of the drilling fluid. The addition of the safety factor ensures that the drilling fluid can maintain the stability of the wellbore in an uncertain geological environment and reduce the danger caused by inaccurate density estimation.

[0055] The last part of the formula is about the rheological properties of the drilling fluid, namely . It is the actual viscosity of the drilling fluid, which indicates the flow resistance of the drilling fluid under specific conditions. The viscosity of the drilling fluid determines its flow characteristics in the wellbore. Too high viscosity may lead to poor fluidity and increase wellbore pressure, while too low viscosity may lead to insufficient resistance to formation pressure. It is the initial viscosity of the drilling fluid, usually measured when the drilling fluid is prepared. and The ratio reflects the degree of adjustment of drilling fluid viscosity as the environment changes during drilling. It is the rheological index of drilling fluid, which is used to describe the relationship between the fluidity of drilling fluid and shear rate. The rheology of drilling fluid is usually nonlinear, that is, the viscosity will change with the change of flow rate. The introduction of makes the calculation more accurate and ensures that the drilling fluid can maintain good fluidity under high pressure environment.

[0056] Furthermore, the safety factor is: .

[0057] When calculating the safety factor, key parameters include the fracture pressure, actual pressure and pore pressure of the formation. The fracture pressure of the formation refers to the maximum pressure that the formation can withstand. If this pressure is exceeded, the formation will rupture, causing serious drilling accidents. The fracture pressure is usually an upper limit value, which indicates the maximum stress that the formation can withstand during the drilling process. In the present invention, this parameter provides a necessary reference framework for determining the safety factor, because the density of the drilling fluid needs to be adjusted to a sufficient level to ensure that the pressure downhole is always kept below the fracture pressure of the formation. If the downhole pressure exceeds the fracture pressure, the well wall will lose stability, leading to the failure of the drilling operation.

[0058] Compared with the fracture pressure, the actual formation pressure is obtained through real-time monitoring on site. The actual pressure is usually smaller than the fracture pressure, but it is affected by many factors, such as the depth of the formation, porosity, rock type, etc. The actual pressure reflects the actual load of the formation during the drilling process, and it plays an important role in adjusting the density of the drilling fluid in real time. By comparing the difference between the actual formation pressure and the fracture pressure, we can preliminarily understand whether the current formation is within the safe range. If the actual pressure is close to the fracture pressure, it means that the pressure on the formation is close to the limit, and any too small pressure margin may cause the well wall to rupture.

[0059] In addition, pore pressure is the pressure generated by fluids (such as water, gas, etc.) in the pores of the formation. Pore pressure is closely related to the porosity and rock properties of the formation, and it reflects the pressure state of the fluid inside the formation. Pore pressure is usually low, but it has a fundamental impact on the actual pressure, and the actual pressure is often increased on the basis of pore pressure. During the drilling process, pore pressure provides a benchmark for calculating the actual pressure. If the pore pressure is too high and the actual pressure is too low, it may cause the penetration of fluids or gas leakage in the formation, which will have an adverse effect on the stability of the wellbore.

[0060] Therefore, the calculation of the safety factor further ensures that the formation can withstand the necessary pressure margin to maintain the stability of the wellbore during drilling by evaluating the difference between the actual pressure, pore pressure and fracture pressure. Specifically, the numerator of the safety factor is the difference between the formation fracture pressure and the actual pressure, that is, , which reflects the additional pressure that the formation can withstand. The denominator is the difference between the actual pressure and the pore pressure, i.e. , which represents the deviation of the formation pressure state relative to its pore pressure. By comparing the two, it is possible to quantify the safety margin between the actual pressure and the fracture pressure of the formation, which helps determine the density of the drilling fluid.

[0061] Safety Factor The larger the value, the more pressure margin the formation can withstand, which means that the density of the drilling fluid can be relatively low, thereby reducing the pressure load on the wellbore wall; conversely, a smaller safety factor means that the formation can withstand less pressure margin, and the density of the drilling fluid must be increased accordingly to provide sufficient support to ensure that the wellbore wall does not break. Therefore, by adjusting the safety factor, the drilling fluid density can be optimized in real time according to the changes in formation pressure, ensuring that the downhole pressure can be effectively controlled under any circumstances.

[0062] The calculation method of the safety factor can not only cope with drilling operations under normal conditions, but also adapt to pressure fluctuations in abnormally high-pressure formations. In abnormally high-pressure formations, since the actual pressure of the formation may be much higher than the expected value, the density of the drilling fluid usually needs to be set relatively high in the initial stage. As drilling progresses, the real-time calculation of the safety factor can dynamically adjust the density of the drilling fluid according to the changes in the actual formation pressure and pore pressure, so that the downhole pressure is always within a safe range. By accurately calculating the safety factor, the well wall can be effectively prevented from rupturing when the pressure is too high, and the problem of excessive well wall stress caused by excessively high drilling fluid density can be avoided, thereby ensuring the smooth progress of drilling operations in abnormally high-pressure formations.

[0063] Furthermore, the safety pressure margin for: .

[0064] first, It is the pressure anomaly coefficient, which reflects the deviation between the actual formation pressure and the normal formation pressure. It can measure the degree to which the formation pressure deviates from the normal pressure, especially in high-pressure abnormal formations, where the actual pressure is much higher than the hydrostatic pressure and rock pressure. The value of is usually larger. In the calculation of drilling fluid density, Multiplying by other factors can help increase the density of drilling fluid to cope with pressure fluctuations caused by abnormally high-pressure formations. The introduction of the pressure anomaly coefficient allows the drilling fluid to be flexibly adjusted to cope with pressure changes under different formation conditions.

[0065] Next, Indicates the pressure of the formation rock, which is generated by the weight of the formation rock and usually increases with the increase of drilling depth. The rock pressure and hydrostatic pressure work together to determine the overall pressure state of the formation. It is the hydrostatic pressure, which is the pressure generated by the deadweight of the drilling fluid. The difference between the hydrostatic pressure and the rock pressure reflects the pressure range that the drilling fluid can withstand at different depths. In high-pressure abnormal formations, the actual formation pressure may far exceed the hydrostatic pressure. Therefore, the difference between the hydrostatic pressure and the rock pressure needs to be balanced by the density of the drilling fluid to ensure that the well wall is not subjected to excessive pressure.

[0066] Indicates the drilling depth, is the depth at which drilling fluid begins to be injected. These two parameters reflect the depth of the formation and the injection of drilling fluid during the drilling process. As the depth increases, the pressure of the formation usually increases, so the density of the drilling fluid needs to increase accordingly to adapt to the pressure change. The effect of depth on the safety pressure margin is measured by This expression shows that as the drilling depth increases, the safety pressure margin will be enlarged in proportion to the square root of the depth, which ensures that the drilling fluid can adapt to greater pressure changes in deeper formations.

[0067] Is the compression index, which describes the compressibility of the rock sample under external pressure. The compression index reflects the elastic properties of the formation rock. The greater the compressibility of the rock, the more obvious the volume change of the formation under pressure. During the drilling process, the compressibility of the formation will affect the adaptability of the drilling fluid to the formation pressure. It indicates the actual stress in the formation, which is the result of the interaction between the pore water pressure and the rock strength in the formation. The greater the effective stress, the stronger the bearing capacity of the formation under pressure. Therefore, it is necessary to ensure the stability of the well wall by increasing the density of the drilling fluid.

[0068] at last, It is the safety factor, which indicates the margin of the formation when it is under pressure. The introduction of the safety factor ensures that the actual pressure of the formation will not exceed its fracture pressure during drilling. When the safety factor is large, it means that the formation can withstand more additional pressure, so the density of the drilling fluid can be relatively low; when the safety factor is small, the pressure margin that the formation can withstand is small, and the density of the drilling fluid needs to be increased to avoid rupture of the well wall.

[0069] Therefore, the safety pressure margin It is calculated by comprehensively considering factors such as formation pressure anomaly, compressibility, depth, effective stress and safety factor. By introducing this parameter, the density of the drilling fluid can be dynamically adjusted to cope with the fluctuation of formation pressure and ensure the stability and safety of the wellbore during the drilling process. The increase in the safety pressure margin means that the drilling fluid can better adapt to the fluctuation of formation pressure, thereby effectively preventing the occurrence of dangerous situations such as wellbore rupture and blowout.

[0070] Furthermore, the dynamic control model is: ; in, is the time variation function of the bottom hole pressure, which is obtained by measuring the bottom hole pressure value in a set time window in real time and constructing a pressure curve function; is the wellbore energy storage coefficient, which is the set value in m³ / MPa; for The inflow rate at time, in m³ / s; for The outflow rate at the time, in m³ / s; is the formation expansion volume, in m³; is the Darcy friction coefficient of drilling fluid flowing in the pipeline; is the borehole diameter, in m; The circulation flow rate of drilling fluid; is the equivalent well section length, in m; is the expansion volume normalization coefficient, which takes values ​​of 100, 200 or 300. The easier the formation is to expand, the higher the value; is the pressure anomaly coefficient.

[0071] In this model, the bottom hole pressure It changes with time. It measures the bottom hole pressure in real time and monitors it within a set time window, thereby constructing a curve function of pressure change over time. This process is particularly important for abnormally high-pressure formations, because the formation pressure often fluctuates violently, and traditional drilling fluid control methods often cannot respond to these fluctuations quickly. By accurately measuring and analyzing the bottom hole pressure, the drilling fluid flow and density can be dynamically adjusted to avoid wellbore instability caused by excessive or low pressure.

[0072] In the dynamic control model, The wellbore energy storage coefficient represents the energy storage and release capacity of the wellbore during the flow of drilling fluid. This parameter reflects the geometry of the wellbore, the flow characteristics of the drilling fluid, and the energy storage characteristics of the formation. The setting of the wellbore energy storage coefficient is very important because it directly affects the response speed to changes in bottom hole pressure. In high-pressure abnormal formations, the formation pressure may change dramatically. Therefore, accurately calculating and adjusting the wellbore energy storage coefficient can ensure that the drilling fluid can respond quickly and maintain stable pressure when the downhole pressure fluctuates.

[0073] Another critical parameter is the flow rate into the well. and outflow rate , they represent the flow rate of drilling fluid entering and leaving the wellbore respectively. The difference between the inflow and outflow rates directly affects the change in downhole pressure. If the inflow rate is too large or the outflow rate is too small, the downhole pressure will rise rapidly, causing the wellbore wall to rupture; conversely, if the inflow rate is too small or the outflow rate is too large, the downhole pressure may not be effectively supported, causing the wellbore wall to collapse. Therefore, by accurately controlling these two flows, the bottom hole pressure can be effectively adjusted to avoid risks caused by excessive or insufficient pressure. Real-time monitoring and dynamic adjustment of the inflow and outflow rates can make drilling operations safer and more reliable.

[0074] The model also introduces the formation expansion volume , which refers to the situation in which the formation volume expands due to pressure changes during the drilling process. Formation expansion is usually closely related to the compressibility, porosity and distribution of fluids in the formation. The volume change of formation expansion will directly affect the fluidity and pressure distribution of the drilling fluid. Therefore, As an important parameter in the dynamic control model, it helps predict and adjust the flow characteristics of the drilling fluid, ensuring that the drilling fluid can adapt to changes in pressure when the formation expands and avoid excessive pressure load on the well wall.

[0075] Darcy friction coefficient It is the friction coefficient of the drilling fluid when it flows in the pipeline. It is closely related to factors such as the viscosity of the drilling fluid, the flow velocity, the roughness of the wellbore, and the diameter of the wellbore. The magnitude of the flow resistance directly affects the change of downhole pressure. The greater the friction resistance, the faster the change of the bottom hole pressure. Especially in high-pressure abnormal formations, changes in flow resistance may cause excessive pressure fluctuations, thereby affecting the stability of the well wall. Therefore, accurately calculating and adjusting the Darcy friction coefficient in real time is the key to ensuring downhole pressure control. By adjusting the fluidity of the drilling fluid and the flow conditions of the wellbore, the bottom hole pressure fluctuations caused by excessive friction resistance can be effectively avoided.

[0076] Wellbore diameter It also plays a key role in the dynamic control model. The diameter of the wellbore determines the flow space of the drilling fluid in the wellbore, which in turn affects the flow velocity and flow resistance. When the wellbore diameter is larger, the flow resistance of the drilling fluid is smaller, and the change rate of the bottom hole pressure is slower; conversely, when the wellbore diameter is smaller, the resistance to the flow of the drilling fluid increases, and the bottom hole pressure will change more rapidly. The change of the wellbore diameter will have an important impact on the regulation of the flow rate. Therefore, in the actual drilling process, the measurement and control of the wellbore diameter is very important.

[0077] Drilling fluid circulation flow It is a key parameter that affects the bottom hole pressure. The size of the circulation flow directly affects the fluidity and pressure distribution of the drilling fluid. In drilling operations, the circulation flow of the drilling fluid usually needs to be dynamically adjusted according to the actual pressure and flow characteristics of the formation. The larger the circulation flow, the easier it is to control the fluctuation of the downhole pressure, but too high a flow may cause the drilling fluid flow to be unstable, which in turn increases the pressure burden on the well wall. By controlling the circulation flow, the bottom hole pressure can be effectively balanced to ensure the stability of the drilling operation.

[0078] Equivalent well section length As a parameter in the model, it reflects the effect of the actual length of the wellbore on the flow of drilling fluid. The equivalent well section length is an assumed value introduced to simplify the effect of the wellbore geometry, which helps to estimate the pressure and flow rate under complex wellbore shapes. By introducing the equivalent well section length, the flow of downhole fluid can be described more accurately and the prediction accuracy of bottom hole pressure changes can be improved.

[0079] Furthermore, the Darcy friction coefficient The calculation formula is: ; in, is the surface roughness of the pipeline; is the pipe diameter; is the Reynolds number.

[0080] first, Indicates the surface roughness of the pipe, which reflects the resistance of the inner surface of the pipe to the flow of fluid. During the drilling process, the roughness of the pipe surface may change with the degree of wear or corrosion of the pipe, so it is very important to accurately measure the roughness of the pipe. The greater the surface roughness, the greater the resistance encountered by the drilling fluid when flowing in the pipe, and the more drastic the change in bottom hole pressure will be. Therefore, It is a key parameter affecting flow resistance and friction coefficient.

[0081] Secondly, It is the diameter of the pipe, which indicates the width of the channel through which the drilling fluid flows. The larger the pipe diameter, the smaller the flow resistance of the drilling fluid, because there is more space for flow, the shear effect of the fluid is weaker, and the flow speed is relatively uniform. On the contrary, the smaller the pipe diameter, the greater the flow resistance and the faster the change of downhole pressure. By controlling the design and diameter of the pipe, the flow resistance can be adjusted to optimize the fluidity of the drilling fluid.

[0082] is the Reynolds number, which represents the ratio between the inertial force and the viscous force of the fluid flow. The Reynolds number is a dimensionless physical quantity, which is used in fluid mechanics to describe the state of fluid flow. When the Reynolds number is small (usually less than 2000), the fluid behaves as laminar flow, the flow is relatively stable, and the friction loss is small; when the Reynolds number is large (usually greater than 4000), the fluid is turbulent, the flow is unstable, and the friction loss is large. During the drilling process, the Reynolds number is usually calculated by measuring the flow rate and viscosity of the drilling fluid, which plays a decisive role in the calculation of the friction coefficient. The larger the Reynolds number, the stronger the turbulent effect of the flow, the greater the shear force of the fluid, and thus a larger friction coefficient.

[0083] In the formula The term introduces the relationship between the Reynolds number and the friction coefficient, reflecting the effect of flow state on friction resistance. Under high Reynolds number conditions, the flow of drilling fluid in the pipeline tends to be turbulent, the friction loss increases, and thus affects the speed of change of downhole pressure. Therefore, understanding the Reynolds number is crucial to accurately predict the change of the friction coefficient.

[0084] This formula calculates the friction coefficient iteratively to obtain the accurate Darcy friction coefficient. The larger the Darcy friction coefficient, the greater the resistance encountered by the drilling fluid when flowing in the pipeline, and the more violent the fluctuation of the bottom hole pressure, which may cause excessive stress on the well wall, thus causing safety hazards. On the contrary, the smaller the Darcy friction coefficient, the smaller the flow resistance, the smaller the fluctuation of the bottom hole pressure, and the well wall remains relatively stable. Therefore, accurately calculating and optimizing the Darcy friction coefficient can not only improve the fluidity of the drilling fluid, but also effectively avoid the rupture of the well wall caused by excessive pressure fluctuations.

[0085] In drilling operations in high-pressure abnormal formations, the formation pressure is often much higher than the conventional design pressure, and the drilling fluid needs to be precisely adjusted according to these abnormal pressures. By dynamically calculating the friction coefficient, the flow characteristics and pressure distribution of the downhole fluid can be evaluated in real time, thereby ensuring the balance between the fluidity of the drilling fluid and the bottom hole pressure. By adjusting the roughness and diameter of the pipeline and optimizing the rheological properties of the drilling fluid, the friction coefficient can be effectively controlled, the fluctuation of the bottom hole pressure can be reduced, and the stability of the well wall can be ensured.

[0086] In actual drilling operations, in addition to the above-mentioned influencing factors, the rheological properties of the drilling fluid also have an important influence on the friction coefficient. Rheological properties include the viscosity and rheological index of the drilling fluid, which will change with the temperature and pressure changes during the drilling process, thus affecting the flow state and friction resistance. By comprehensively considering these factors, the fluidity of the drilling fluid can be adjusted more accurately and the control of downhole pressure can be further optimized.

[0087] Furthermore, the downhole pressure constraint relationship is: the bottom hole pressure is less than the formation fracture pressure 1.5 times of.

[0088] Formation fracture pressure It is the critical pressure at which the formation breaks when it is subjected to excessive pressure. Specifically, when the downhole pressure exceeds this critical value, the rock in the formation may crack or break, resulting in serious consequences such as wellbore collapse and blowout. Therefore, ensuring that the downhole pressure is lower than the formation fracture pressure is a basic requirement in drilling operations. Since the formation pressure may change due to various factors (such as fluid injection, changes in formation properties, etc.) during the drilling operation, simply restricting the equivalence relationship between the bottomhole pressure and the fracture pressure may not be able to fully cope with all dynamic pressure fluctuations. Therefore, the constraint relationship of setting the bottomhole pressure to 1.5 times the formation fracture pressure is to reserve sufficient safety margin for the downhole pressure during the drilling process to avoid pressure fluctuations causing wellbore fractures.

[0089] Specifically, this constraint relationship shows that in actual drilling operations, the bottom hole pressure must always be kept within 1.5 times the formation fracture pressure. This 1.5-fold safety factor provides a certain buffer space to cope with temporary increases in bottom hole pressure caused by pressure fluctuations, drilling fluid injection or other factors. In fact, during the drilling process, the downhole pressure may be affected by many factors, such as changes in the flow rate of drilling fluid, changes in formation lithology, and other operating conditions. Therefore, by adopting this pressure constraint relationship, the flow rate and density of the drilling fluid can be adjusted in real time to ensure that the downhole pressure does not exceed the set upper limit, thereby preventing well wall rupture and other potential risks caused by excessive pressure.

[0090] The setting of this constraint relationship is not absolutely static, but is adjusted in combination with the dynamic situation in actual drilling operations. During the drilling process, the downhole pressure will vary depending on the formation. For abnormally high-pressure formations, the downhole pressure is usually much higher than the conventional formation pressure, and the formation pressure will gradually increase with increasing depth. Therefore, the downhole pressure needs to be precisely controlled to ensure that it does not exceed 1.5 times the formation fracture pressure. This constraint relationship not only helps to formulate a reasonable drilling fluid density and flow adjustment plan, but also ensures the safety and stability of drilling operations.

[0091] The above shows and describes the basic principles, main features and advantages of the present invention. Those skilled in the art should understand that the present invention is not limited to the above embodiments. The above embodiments and descriptions only describe the principles of the present invention. The present invention may be subject to various changes and improvements without departing from the spirit and scope of the present invention. These changes and improvements fall within the scope of the present invention. The scope of protection claimed by the present invention is defined by the attached claims and their equivalents.

Claims

1. A drilling fluid optimization control method based on prediction of abnormal high-pressure formation pressure, characterized in that: include: Step 1: According to the geological characteristic parameters of the target formation, a pressure anomaly coefficient model of the target formation is established, and the pressure anomaly coefficient is calculated to evaluate the degree to which the actual formation pressure deviates from the normal pressure; wherein the target formation is a high-pressure abnormal formation, and its actual formation pressure is higher than the set pressure threshold; Step 2: Calculate the optimal drilling fluid density based on the pressure anomaly coefficient to balance the formation pressure while ensuring wellbore stability; Step 3: According to the time change rate of the bottom hole pressure, a dynamic control model for coupling the inflow and outflow of the downhole pressure drilling fluid under the optimal drilling fluid density is established; the downhole pressure constraint relationship is set, and the downhole flow rate and outflow flow rate are adjusted in real time through the dynamic control model; Geological characteristic parameters include: actual formation pressure , unit is MPa; hydrostatic pressure , unit is MPa; formation porosity ; Stratigraphic depth , unit is m; formation compaction coefficient , which indicates the degree of change of formation porosity with depth in the target formation, obtained through experimental calibration; rock pressure , unit is MPa; formation pore pressure , unit is MPa; formation fracture pressure , unit is MPa; The pressure anomaly coefficient model is: ； in, is the pressure anomaly coefficient; The depth at which drilling fluid injection begins; The porosity of the formation corresponding to the depth at which drilling fluid injection begins.

2. The drilling fluid optimization control method based on high-pressure abnormal formation pressure prediction according to claim 1 is characterized in that: Calculate the optimal drilling fluid density based on the pressure anomaly coefficient : ； in, is the density of water, in kg / cm³; is the solid specific gravity of the rock and soil sample of the target stratum; is the compression index, in units of , obtained by obtaining rock and soil samples of the target stratum and then conducting triaxial tests on the rock and soil samples; It is the ratio of formation porosity to the volume of formation solid particles when the drilling fluid begins to be injected. is the effective stress, in MPa; is the acceleration due to gravity, which is a constant; is the safety pressure margin, in MPa; is the drilling fluid viscosity, in mPa·s; is the rheological index of drilling fluid; is the initial viscosity of the drilling fluid, in mPa·s; is the safety factor.

3. The drilling fluid optimization control method based on high-pressure abnormal formation pressure prediction according to claim 2, characterized in that: The dynamic control model is: ； in, is the time variation function of the bottom hole pressure, which is obtained by measuring the bottom hole pressure value in a set time window in real time and constructing a pressure curve function; is the wellbore energy storage coefficient, which is the set value in m³ / MPa; for The inflow rate at time, in m³ / s; The outflow rate at the time, in m³ / s; is the formation expansion volume, in m³; is the Darcy friction coefficient of drilling fluid flowing in the pipeline; is the borehole diameter, in m; The drilling fluid circulation flow rate; is the equivalent well section length, in m; is the expansion volume normalization coefficient, which takes values ​​of 100, 200 or 300. The easier the formation is to expand, the higher the value; is the pressure anomaly coefficient.

4. The drilling fluid optimization control method based on high-pressure abnormal formation pressure prediction according to claim 3 is characterized in that: The safety factor is: 。 5. The drilling fluid optimization control method based on high-pressure abnormal formation pressure prediction according to claim 4 is characterized in that: Safety pressure margin for: 。 6. The drilling fluid optimization control method based on high-pressure abnormal formation pressure prediction according to claim 5 is characterized in that: Darcy friction coefficient The calculation formula is: ； in, is the surface roughness of the pipeline; is the pipe diameter; is the Reynolds number.

7. The drilling fluid optimization control method based on high-pressure abnormal formation pressure prediction according to claim 6 is characterized in that: The downhole pressure constraint relationship is: the bottom hole pressure is less than the formation fracture pressure 1.5 times of.

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