High-pressure brine layer drilling fluid density optimization and pressure control system

Abstract

The invention discloses a high-pressure brine layer drilling fluid density optimization and pressure control system, and relates to the technical field of automatic control. Comprising a data acquisition part used for acquiring salt water layer data and drilling data; the osmotic pressure model part is used for establishing an osmotic pressure model considering the saline crystallinity and the temperature-pressure effect to obtain the osmotic pressure of the saline layer; the drilling fluid density analysis and control part is used for evaluating the influence of the salt solubility in the saline layer on the drilling fluid density and establishing a coupling model of the saline layer solubility and the drilling fluid density to obtain the optimal drilling fluid density so as to control the drilling fluid density; and the safe drilling pressure analysis and control part is used for calculating safe drilling pressure according to the formation fracture pressure and the optimal drilling fluid density and setting a safe drilling pressure window according to the safe drilling pressure so as to control the drilling pressure. According to the invention, intelligent regulation and control of drilling fluid density and dynamic control of pressure are realized.

Description

Technical Field

[0001] The invention relates to the field of automatic control technology, and in particular to a high-pressure salt water layer drilling fluid density optimization and pressure control system. Background Art

[0002] In the process of exploration and development of deep resources such as oil and natural gas, drilling fluid, as a key medium in downhole operations, undertakes multiple tasks such as stabilizing the well wall, carrying cuttings, controlling downhole pressure, and preventing blowouts. With the continuous increase in drilling depth, drilling operations gradually enter a complex geological environment of high temperature and high pressure, especially in high-pressure salt water layers. Due to the high mineralization of the formation, poor permeability, strong plasticity of the rock structure, and extreme thermodynamic conditions, traditional drilling fluid density control methods face many challenges. In this context, how to achieve dynamic optimization of drilling fluid density and intelligent regulation of pressure windows has become an important technical difficulty in ensuring well control safety and improving efficiency and reducing consumption.

[0003] In the prior art, the control of drilling fluid density mainly relies on artificial experience and simplified formation mechanics models. Common methods include: empirical formula estimation based on formation pressure gradient, static geostress inversion method, and manually setting the safety pressure window after obtaining the fracture pressure through micro-fracture test. Although these methods have certain applicability under conventional geological conditions, their limitations gradually emerge in the environment of high-pressure salt water layers. First, the prior art generally ignores the dynamic effect of the dissolution-crystallization behavior of salt in high-pressure salt water layers on the density of drilling fluid. Under high temperature and high pressure conditions, a large number of soluble minerals in the salt rock layer will undergo complex physical and chemical reactions with the drilling fluid, resulting in rapid fluctuations in the density of the solution, which in turn causes changes in downhole pressure and decreased wellbore stability. Traditional methods usually assume that the salt layer is an inert structure and do not consider the interfacial mass transfer process between the drilling fluid and the salt rock, thereby underestimating the disturbance of the pressure field caused by density changes, which can easily cause wellbore rupture or well leakage. Secondly, the existing density optimization technology often uses a fixed parameter model and lacks the ability to perceive changes in permeability pressure in real time. In complex well sections, the permeability, pore structure, temperature gradient and other parameters of the formation change with depth, resulting in a dynamic change trend in the osmotic pressure. However, it is difficult for fixed models to accurately reflect this process, which is prone to control lag or misjudgment. For example, there is currently a technology that adjusts the density by setting a fixed osmotic pressure difference or constant saturation, but during the sudden crystallization period of the salt water layer, this method cannot predict the sudden pressure drop, which can easily cause well control accidents. Summary of the invention

[0004] In view of this, the present invention provides a high-pressure saltwater layer drilling fluid density optimization and pressure control system, which realizes the intelligent regulation of drilling fluid density and dynamic control of pressure. The system significantly improves the safety, adaptability and control accuracy during the drilling process of complex saltwater layers, and effectively prevents accidents such as well wall rupture and blowout.

[0005] The technical solution adopted by the present invention is as follows: A high-pressure saltwater layer drilling fluid density optimization and pressure control system, comprising: The data acquisition part is used to acquire saltwater layer data and drilling data; The osmotic pressure model part is used to establish an osmotic pressure model that takes into account the brine crystallinity and temperature and pressure effects, and obtain the osmotic pressure of the brine layer; The drilling fluid density analysis and control part is used to evaluate the effect of salt solubility in the brine layer on the drilling fluid density, establish a coupling model between the brine layer solubility and the drilling fluid density, and obtain the optimal drilling fluid density to control the drilling fluid density; The safety drilling pressure analysis and control part is used to calculate the safety drilling pressure according to the formation fracture pressure and the optimal drilling fluid density, and to set the safety drilling pressure window according to the safety drilling pressure to control the drilling pressure.

[0006] Furthermore, the saltwater layer data includes: the density of the saltwater layer fluid , unit is kg / m³; activation energy of brine , in J / mol; permeability of saline layer , in m²; molar volume of salt , in m³ / mol; maximum salt solubility , in mol / L; contact area between drilling fluid and salt water layer , in m²; salt dissolution rate constant , unit is m / s; salt concentration change rate , the unit is ; is the time, in seconds; the salt concentration of the saline layer , unit is mol / L; thermal expansion coefficient of salt water layer, value range is arrive , the unit is .

[0007] Furthermore, drilling data includes: current depth , in m; depth of top of saline layer , unit is m; formation temperature , unit is K; stratum thickness , unit is m; formation compaction index , the value range is 0.7 to 1.3; the basic density of water-based drilling fluid , unit is kg / m³; internal friction angle of salt rock , unit is rad; true vertical depth , unit is m; circulation flow rate , in m / s; average pore diameter , unit is m; drilling fluid viscosity , the unit is .

[0008] Furthermore, the formation fracture pressure The unit is MPa and is determined through micro-crack test. The specific steps include: conducting the test below the casing shoe, in an open well section or a bare hole section, selecting a layer that does not interfere with other layers, using a bridge plug or a packer to isolate the test section to prevent liquid leakage to other layers, injecting drilling fluid or fracturing fluid into the test section, gradually pressurizing until the initial crack opens, and recording the pressure-time curve. After the pressure reaches a certain inflection point, it no longer rises linearly, and the liquid suddenly leaks into the formation and forms cracks. This inflection point is the formation fracture pressure, which is manifested as: the pressure stops rising instantly or drops slightly, and the pressure relief curve shows a sudden change.

[0009] Furthermore, the osmotic pressure model is: ; in, is the osmotic pressure of the saline layer; is the reference pressure, which is 10.1MPa; It is the crystallinity term of salt water, which indicates the ratio between the dissolved state and the crystalline state in salt water under certain temperature and pressure conditions. It determines whether the salt exists stably in the solution in an ionic state or has begun to crystallize out. The higher the crystallinity, the more salt exists in the solid form, resulting in a lower solution density. When the density of salt water is higher than the standard water density, there is more dissolved salt and the crystallinity is low. When the density of salt water is close to or lower than the standard water density, it means that there is less dissolved salt or some salt has crystallized. The ratio approaches 1 or is less than 1, and the osmotic pressure decreases. is the gas constant, with a value of 8.314 and a unit of ; is the reference temperature, the value is 298.15, the unit is K; is the crystallinity sensitivity coefficient.

[0010] Furthermore, the crystallinity sensitivity coefficient The value of ; is the absolute value operator.

[0011] Furthermore, the optimal drilling fluid density for: ; in, Maximum density increase due to salt, in kg / m³.

[0012] Furthermore, the maximum density increase contributed by salt is Indicates that when there is no salt in the drilling fluid, the drilling fluid density is the basic density of the water-based drilling fluid ; As salt is added, the density of the drilling fluid gradually increases. Assuming that the salt reaches its maximum solubility and completely dissolved, the drilling fluid density will reach a limit value ,at this time: .

[0013] Furthermore, safe drilling pressure for: .

[0014] By adopting the above technical scheme, the present invention produces the following beneficial effects: it can realize dynamic perception, intelligent control and real-time feedback of density and pressure during drilling. By introducing the osmotic pressure model that considers salt crystallinity, thermal expansion effect and osmotic-reaction kinetic coupling mechanism, the pressure change process under the complex flow-solid-heat action of the salt layer is effectively characterized, and the accuracy and response speed of density control are significantly improved. At the same time, the optimal density calculation formula integrates salt concentration, osmotic pressure and thermal disturbance factors, so that density regulation has high adaptability and can achieve precise control under different formation environments. In addition, by constructing a pressure window expression model based on formation fracture pressure, shear stress and pore seepage correction terms, full-scale control from static mechanical boundary to microscopic dynamic pressure drop is realized, avoiding safety risks such as well wall rupture, well leakage and blowout. The system has high integration and algorithm capabilities, is suitable for various deep high-pressure salt water sections, has significant safety, reliability and engineering practicality, and fills the technical gap of poor adaptability of traditional empirical density control and fixed window methods under extreme working conditions. BRIEF DESCRIPTION OF THE DRAWINGS

[0015] Figure 1 It is a schematic diagram of the system structure of the high-pressure salt water layer drilling fluid density optimization and pressure control system in an embodiment of the present invention. DETAILED DESCRIPTION

[0016] All features disclosed in this specification, or steps in all methods or processes disclosed, except mutually exclusive features and / or steps, can be combined in any manner.

[0017] Any feature disclosed in this specification (including any additional claims and abstract), unless otherwise stated, may be replaced by other alternative features that are equivalent or have similar purposes. That is, unless otherwise stated, each feature is only an example of a series of equivalent or similar features.

[0018] Example 1, reference Figure 1 :A high-pressure salt water layer drilling fluid density optimization and pressure control system, comprising: The data acquisition part is used to acquire saltwater layer data and drilling data; In the high-pressure salt water layer drilling fluid density optimization and pressure control system, the data acquisition part is the premise and basis for the realization of the whole system function. Its core task is to realize the real-time perception and high-precision analysis of the downhole high-pressure salt water layer environmental information, so as to provide key parameter support for the subsequent permeability pressure modeling, density control algorithm and pressure window calculation. This part mainly realizes the fusion collection of multi-source heterogeneous data through the collaborative work with downhole measurement tools, wellhead sensing systems and formation prior databases. High-pressure salt water layers are often buried in deep formations. They have high temperature, high pressure, high fluid mineralization, and strong chemical reactivity and crystallization precipitation trends. Therefore, the accurate perception of their physical, chemical and fluid mechanical properties directly determines the effectiveness and safety of drilling fluid density and wellbore pressure control. When the system is deployed, the depth, temperature, formation thickness, compaction degree and pore structure data of the salt layer are collected through measurement while drilling (LWD) and borehole cable measurement technology; at the same time, the pressure response characteristics of the in-situ porous fluid are obtained through formation pressure testing tools (such as micro-pressure testers) to determine the formation permeability and possible fluid permeation mode; in addition, the pore size, permeability and rock physical properties of the salt layer are extracted by core sampling analysis or downhole imaging, and the salt concentration, dissolution rate change and density evolution trend are detected through the drilling fluid annulus return online sampling system. These data constitute the physical boundary conditions for the interaction between the salt layer fluid and the rock mass. In order to accurately describe the dissolution-crystallization behavior of the brine and the change in osmotic pressure under its influence, the system needs to dynamically obtain key physical and chemical parameters such as the density, activation energy, molar volume, maximum solubility and salt concentration change rate of the brine fluid. The activation energy is extracted by a thermal analyzer, the molar volume is estimated by combining experimental data and the state equation, and the concentration change rate is calculated by time series analysis of the return fluid sample. Considering the violent volatility of downhole conditions and the limitation of well diameter, the system adopts the combination of high-temperature and high-pressure micro-sensor chips and optical fiber sensors to ensure high-precision data acquisition while having good downhole adaptability and corrosion resistance. In the process of data acquisition, it is also necessary to combine the real-time drilling data stream, such as drilling depth, drilling fluid circulation speed, drilling fluid viscosity, etc., and transmit it to the ground processing system in real time through the well control platform, and perform pre-processing operations such as denoising, interpolation, and spatiotemporal registration. The entire data acquisition process emphasizes the continuity, spatial correlation and real-time response capability of the data, and uses machine learning algorithms to identify dynamic modeling parameters and distinguish states, thereby providing the permeability pressure model with input that is highly close to the actual field, so that the subsequent density optimization and pressure control calculations no longer rely on empirical rules, but are based on the coupling model results dynamically generated based on measured data, which fundamentally improves the safety and adaptability of high-pressure salt water layer drilling operations. This data acquisition part not only ensures the accuracy of system modeling, but also realizes the high-fidelity bridge between the downhole physical world and the modeling calculation world, which is the key basis for the present invention to achieve dynamic response and intelligent regulation in complex salt water layer environments.

[0019] The osmotic pressure model part is used to establish an osmotic pressure model that takes into account the brine crystallinity and temperature and pressure effects, and obtain the osmotic pressure of the brine layer; In the high-pressure saltwater layer drilling fluid density optimization and pressure control system, the realization of the permeability pressure model is the core link for the system to respond to the downhole fluid-rock coupling characteristics and build a dynamic density control mechanism. Since the high-pressure saltwater layer has extremely complex thermodynamic behavior and microscopic seepage mechanism, its permeability pressure is not only affected by conventional formation pressure and porosity, but more importantly depends on the brine crystallinity, dissolution heat effect and solute diffusion and migration characteristics under high temperature and high pressure. Therefore, the model must integrate the theoretical foundations of thermodynamics, dynamics and geophysics. In actual implementation, the permeability pressure model is not a static constant, but a function expression that evolves with time and space. It is based on the parameters such as brine density, solubility limit, activation energy, molar volume and concentration change rate obtained on site. By coupling the material migration mechanism and the formation compaction state, it dynamically describes the permeability potential difference and stress transfer relationship between the drilling fluid and the saltwater layer. The core idea of ​​the model is to convert the ratio of crystalline and dissolved states in brine into an effective crystallinity index, and combine the ratio of brine density to standard water density to quantify whether the salt is in a supersaturated precipitation or metastable dissolution state. This state change directly affects the fluid exchange rate and direction between the drilling fluid and the formation, thereby affecting the actual response of pore pressure. Furthermore, the model introduces the activation energy parameter of salt migration in the formation, and expresses the energy barrier that salt needs to overcome from the rock mass to the drilling fluid through the temperature dependence term, reflecting the hysteresis and nonlinearity of the dissolution behavior on the permeation process. At the same time, the correction effect of molar volume and maximum solubility on the proportion of salt in unit volume is considered, which enhances the adaptability of the model to different mineral components and saturation characteristics. In addition, considering the compaction trend of the brine layer with depth, the model also embeds a geological deformation factor constructed based on the formation depth, thickness and compaction index to express the changes in the pressure transmission path and rate after the permeation channel is compressed and deformed, so that the model no longer idealizes the assumption of uniform pores, but adapts to the heterogeneous and non-steady-state seepage behavior that actually exists in complex stress fields. In the specific implementation process, the various parameters required by the model are provided in real time by the data acquisition part, and are numerically solved or iteratively approximated through multi-physics coupling equations, and the final output is a dynamic permeability pressure value that can be used for subsequent density control and pressure window analysis. In order to improve the stability and accuracy of the model under high temperature and high pressure well conditions, the system also introduces a parameter sensitivity adjustment mechanism, that is, when identifying abnormal changes in downhole temperature and concentration, the weights of the crystallinity index and compaction index are automatically corrected to adapt to the permeability disturbance caused by sudden changes in wellbore conditions or sudden dissolution processes. This model not only reflects the deep coupling relationship between the physical state transformation of salt and the permeability behavior during drilling, but also provides real-time input based on physical mechanisms rather than empirical values ​​for subsequent drilling fluid density adjustment, making drilling operations more predictable and adaptable.It is precisely because of the scientific construction and dynamic realization of the permeability pressure model that the drilling fluid density optimization strategy proposed in the present invention has the ability to deeply respond to the complex environment of the underground high-pressure salt water layer, thereby maximizing the unity of drilling efficiency and safety while ensuring the stability of the well wall and avoiding leakage and blowout.

[0020] The drilling fluid density analysis and control part is used to evaluate the effect of salt solubility in the brine layer on the drilling fluid density, establish a coupling model between the brine layer solubility and the drilling fluid density, and obtain the optimal drilling fluid density to control the drilling fluid density; The drilling fluid density analysis and control part is the core link of the whole system to achieve dynamic closed-loop regulation. Its design concept is not only based on the conventional drilling fluid static pressure control logic, but also fully integrates the physical and chemical characteristics of high-pressure salt water layers, especially the dissolution behavior of salt in high temperature and high pressure environment, the evolution of crystallization state and the deep influence of osmosis on the density evolution process. The implementation process of this part first relies on the output results of the front-end osmotic pressure model, and maps the actual solute migration and crystal precipitation behavior in the salt water layer into a pressure response function through a mathematical model, and then couples with the salt concentration state monitored in real time in the drilling fluid for analysis, and constructs the driving factor field of density regulation. The core of the density analysis model is to accurately identify the nonlinear growth relationship between salt solubility and solution density, that is, as the salt concentration increases, the drilling fluid density does not increase linearly, but shows a slowing or even unstable growth rate when approaching the critical point of maximum solubility. This behavior is particularly obvious in high-pressure salt water layers. Therefore, the system constructs an exponential response density growth function. The input of this function includes the current salt concentration, the osmotic pressure of the salt layer, the maximum solubility and the reference pressure. The marginal effect of salt addition on density improvement is approximately described by the exponential decay function, avoiding the problem of accuracy loss in the high concentration range of the traditional linear model. At the same time, in order to consider the thermal disturbance effect of downhole temperature changes on fluid density, the system introduces a temperature correction term and embeds the parameterization of the thermal expansion effect into the density increment expression, so that the density prediction has the ability to respond to the thermal-material dual field. In the density control execution layer, the system uses the dynamically generated optimal density as the target value, controls the salt injection rate and fluid replenishment ratio through the drilling fluid mixing device, and compares it with the density detection results of the real-time reflux fluid to achieve closed-loop correction of density regulation. A response boundary threshold mechanism is also introduced into the control logic. When the actual density deviates from the predicted density and exceeds the set tolerance interval, the system automatically corrects the solute addition strategy or reduces the pump speed to prevent fluctuations in the circulation system caused by over-adjustment. In terms of data-driven, this part relies on the temperature, pressure, salt concentration and drilling fluid rheological parameters obtained in real time by the multi-sensor fusion system, and predicts the density evolution trend through the time series analysis method of the sliding window to ensure that the control strategy is not only optimal for the current state, but also forward-looking for trend changes in the short term. The density analysis and control module is also linked with the safety pressure window model. When the calculated density value approaches the upper or lower limit of the safety limit, the system will automatically determine whether there is a risk of well wall rupture or well kick, and trigger the early warning mechanism to adjust the density strategy in time or recommend suspension of drilling, so as to ensure that the entire drilling process operates within a safe and controllable range.In general, the density analysis and control part of the present invention not only has the ability to quantitatively model the response to the characteristics of the salt water layer, but also constructs a complete "perception-analysis-adjustment-feedback" closed-loop control chain. It is the key to the system's intelligent and dynamic density regulation and pressure management, and effectively improves the safety, stability and adaptability of drilling operations in deep high-pressure salt water formations.

[0021] The safety drilling pressure analysis and control part is used to calculate the safety drilling pressure according to the formation fracture pressure and the optimal drilling fluid density, and to set the safety drilling pressure window according to the safety drilling pressure to control the drilling pressure.

[0022] The core goal of this part is to determine in real time an operational pressure window with engineering safety margin based on the ever-changing permeability environment of the salt water layer and the dynamic adjustment of the drilling fluid density, so that the drilling operation will not trigger formation ruptures and cause leakage, and can effectively suppress the risk of formation fluid invasion and blowout. Since high-pressure salt water layers generally have low permeability and high pressure characteristics, the permeability pressure gradient formed near the well wall has a significant impact on the stress state of the wellbore, and the salt rock formation is more prone to plastic deformation or shear fracture due to its small internal friction coefficient. Therefore, conventional formation pressure calculation methods are difficult to adapt to this kind of geological environment with strong thermal coupling and fluid-solid interaction. This system dynamically obtains the current osmotic pressure state of the salt water layer through the front-end permeability pressure model, and combines the real-time calculated drilling fluid density data to construct a safe drilling pressure assessment model that comprehensively considers the influence of downhole shear stress, seepage effect, lithology physical parameters and dynamic viscosity. In the specific implementation process, firstly, the formation fracture pressure of the current drilling section is obtained based on the downhole micro-fracture test data, and this pressure is used as the upper control boundary; secondly, the effective support pressure generated by the drilling fluid column on the wellbore wall is derived through high-precision formation imaging and wellbore stability analysis, and then combined with the formation shear parameters such as the internal friction angle of salt rock, pore size and compaction degree, the transmission efficiency of this support force in the heterogeneous porous environment is corrected. In order to further consider the influence of the actual seepage behavior of the drilling fluid in the microporous channel on the effective pressure, the system introduces a shear seepage correction term based on the drilling fluid flow rate, viscosity and formation permeability. This correction term can characterize the pressure drop loss in the pores and the stress transfer mechanism inside the salt layer rock body during the continuous circulation of high-density drilling fluid. In the model operation, the drilling fluid density is dynamically embedded in the overall calculation process as a real-time controllable variable to ensure that its adjustment does not exceed the critical threshold of crack formation, while having a sufficient lower limit to resist sudden salt water intrusion or pressure disturbance. In addition, considering that the chemical behavior of saltwater layers under high temperature and high pressure environments is time-varying, the module also integrates the modulation effect of temperature evolution and crystallization precipitation process on the mechanical behavior of the formation, that is, when the downhole temperature rises and causes further precipitation of salt, the pore compression and mechanical strength of the rock mass evolve synchronously, which may cause crack initiation or permeability mutation. The system timely adjusts the pressure window assessment results through thermal correction items, so that the output safety pressure upper and lower limits are in line with the actual state of the current drilling environment, and have the ability to adapt to short-term dynamic changes. Finally, according to the pressure window results formed by the linkage of the above complex variables, the system sends control instructions to the well control device and density adjustment module to realize feedback control of the drilling fluid density, and adjusts the drilling pressure, pump speed or suspends drilling when necessary to ensure that the entire operation process is always within the mechanical and fluid safety area.Through this highly dynamic and multi-factor coupled safe drilling pressure analysis and control strategy, the present invention significantly improves the adaptability, intelligence and inherent safety level of drilling operations under complex high-pressure saline layer conditions, breaks through the safety bottleneck brought about by traditional reliance on experience windows and static boundary judgment, and becomes an indispensable core technical support for achieving efficient and stable drilling in saline layer environments.

[0023] When setting the safety pressure window, take the safety drilling pressure as the center value, set an upper radius threshold and a lower radius threshold, add the upper radius threshold to the safety drilling pressure to get the upper limit of the safety pressure window, and subtract the lower radius threshold from the safety drilling pressure to get the lower limit of the safety pressure window.

[0024] Furthermore, the saltwater layer data includes: the density of the saltwater layer fluid , unit is kg / m³; activation energy of brine , in J / mol; permeability of saline layer , in m²; molar volume of salt , in m³ / mol; maximum salt solubility , in mol / L; contact area between drilling fluid and salt water layer , in m²; salt dissolution rate constant , unit is m / s; salt concentration change rate , the unit is ; is the time, in seconds; the salt concentration of the saline layer , unit is mol / L; thermal expansion coefficient of salt water layer, value range is arrive , the unit is .

[0025] Density of saline fluid It is a basic parameter that describes the overall mass distribution of fluid in a saltwater layer. It not only reflects the salt concentration in the solution, but also indirectly affects the calculation of the crystallinity term, becoming an important basis for judging whether the salt is in a supersaturated precipitation or stable dissolution state in the estimation of osmotic pressure. Its unit is , which can be measured by density meter, fluid inclusion analysis or downhole fluid sampling equipment. It reflects the energy barrier that needs to be overcome to release salt from solid minerals into liquid solutions, and directly affects the sensitivity of temperature to solubility in thermodynamic modeling. Its unit is J / mol, which can be determined by thermal analysis methods such as differential scanning calorimetry (DSC). The level of activation energy will significantly affect the temperature response range of solute migration rate and is the basis for controlling reactive seepage between drilling fluid and brine layer. It is an important parameter to measure the permeability of the formation to drilling fluid or fluid. The unit is m². Its size directly affects the degree of effect of the drilling hydraulic column on the well wall and the strength of the osmotic pressure drop compensation term. It plays a core role in the pressure window correction. This value is generally determined by core analysis or downhole pressure response test. Salt molar volume It is used to measure the volume occupied by a unit mass of salt in the formation. The unit is m³ / mol. It and the activation energy together determine the spatial distribution characteristics of salt under thermal action and affect the intensity of the material migration term in the osmotic pressure model. For high-concentration salt water, the molar volume determines the swelling or shrinking tendency of the system under high temperature and pressure. Maximum salt solubility It is the upper limit of the solubility-density coupling model. It indicates the saturation value of soluble salt in the drilling fluid under the current temperature and pressure conditions. The unit is mol / L and is obtained through dissolution experiments or state equation derivation. When the salt concentration approaches or exceeds this value, crystallization is inevitable, which will cause severe disturbances to the viscosity, filtration loss and density of the drilling fluid. Contact area It is a geometric parameter describing the interaction strength between the drilling fluid and the brine layer interface, and its unit is , which affects the interfacial reaction area during the dissolution process and is an important factor in the solute migration rate. This value depends on the wellbore diameter, well section length and lithology fragmentation, and can be derived from the wellbore trajectory and downhole imaging. Salt dissolution rate constant It is a kinetic parameter that reflects the migration ability of solutes from the formation to the drilling fluid. The unit is m / s. It determines the total amount of salt that can be transmitted per unit time in combination with the contact area. It dominates the slope of the concentration evolution curve in dynamic modeling. Describes the changing trend of salt concentration per unit time in the saltwater layer, in units of , is an important indicator of whether the dissolution-crystallization process is in a steady state, and needs to be obtained through real-time sampling and online chemical analysis instrumentation. It participates in multiple models as a state variable. It is a key input in dynamic modeling to determine whether to enter the precipitation zone and whether to adjust the density or pressure. Its unit is mol / L. Finally, the thermal expansion coefficient of the salt water layer is a parameter used to describe the volume change and density fluctuation of the salt water under high temperature conditions. Its unit is , and its value range is set to arrive , which can be obtained through experimental calibration or table lookup and embedded in the overall model as a thermal correction factor in the drilling fluid density calculation.

[0026] Furthermore, drilling data includes: current depth , in m; depth of top of saline layer , unit is m; formation temperature , unit is K; stratum thickness , unit is m; formation compaction index , the value range is 0.7 to 1.3; the basic density of water-based drilling fluid , unit is kg / m³; internal friction angle of salt rock , unit is rad; true vertical depth , unit is m; circulation flow rate , in m / s; average pore diameter , unit is m; drilling fluid viscosity , the unit is .

[0027] Current drilling depth and the depth of the top of the saline layer The difference between the values ​​of and constitutes the core variable of the depth normalization in the permeability pressure modeling. The form and thickness of the stratum Together they construct a geometric factor for the degree of deep compaction, which is related to the compaction index After combining, a high-order weight is formed to describe the reduction of effective pore space in the formation and the change of fluid pressure transmission path, which is used to adjust the nonlinear amplification effect of permeability pressure with depth. In the present invention, it is not only used as a geometric weight factor to describe the degree of formation deformation, but also used to calculate the crystallinity sensitivity coefficient in the permeability model. This logic realizes the dynamic linkage between geological structure and salt state, so that the amplification effect of crystallinity can be naturally adjusted with the depth of the well, improving the adaptability of the model. It is the thermodynamically dominant variable of the whole system. It not only participates in the thermal expansion correction term in the optimal density expression, but also is the exponential bottom value of the activation energy exponential function in the osmotic pressure model. Under high temperature conditions, the energy barrier of salt activation and dissolution is easier to overcome, thus affecting the salt migration rate, concentration evolution speed and interface reaction intensity with drilling fluid, and ultimately causing the osmotic pressure field to fluctuate significantly with temperature. Therefore, this system requires high-precision temperature input and constructs a temperature difference normalization term in the algorithm. , which is used to weigh the effect of thermal disturbance on the permeability response at different depths.

[0028] Basic density of water-based drilling fluid is the starting baseline of the optimal density model and is used to calculate the upper limit of the salt density contribution , that is, the system identifies the concentration-density range of the current drilling fluid. Correspondingly, the internal friction angle of salt rock It is used to construct the shear strength term, which is the key variable for judging the risk of wellbore rupture in the safe pressure window. The shear stress expression established by the Mohr-Coulomb criterion is Mapped to a static strength threshold, it acts as a constraint upper limit in the pressure regulation strategy to avoid shear fracture of the formation due to excessive density. It is an important geometric parameter for converting the actual wellbore position to the formation pressure. It is linked with density to form the hydrostatic term. , which provides a mechanical basis for the subsequent establishment of the pressure drop correction coefficient. In the seepage loss correction model, the drilling fluid circulation velocity The average pore diameter , drilling fluid viscosity Together, they determine the actual viscous resistance and pressure drop attenuation in the microscopic permeable channel. Specifically, under low flow rate or high viscosity conditions, the pressure drop term is weakened, and the support force of the drilling fluid on the well wall tends to be stable. When the pore size becomes larger or the flow rate increases, the density needs to be increased to compensate for the pressure drop.

[0029] Furthermore, the formation fracture pressure The unit is MPa and is determined through micro-crack test. The specific steps include: conducting the test below the casing shoe, in an open well section or a bare hole section, selecting a layer that does not interfere with other layers, using a bridge plug or a packer to isolate the test section to prevent liquid leakage to other layers, injecting drilling fluid or fracturing fluid into the test section, gradually pressurizing until the initial crack opens, and recording the pressure-time curve. After the pressure reaches a certain inflection point, it no longer rises linearly, and the liquid suddenly leaks into the formation and forms cracks. This inflection point is the formation fracture pressure, which is manifested as: the pressure stops rising instantly or drops slightly, and the pressure relief curve shows a sudden change.

[0030] In the high-pressure salt water layer drilling fluid density optimization and pressure control system involved in the present invention, the formation fracture pressure The accurate acquisition of is the key control indicator to ensure the stability of the wellbore and avoid complex underground accidents such as crack-induced leakage. In order to meet the precise needs of the special geological environment of high-pressure salt water layers, this system uses the micro-crack test method to measure the fracture pressure on site, and builds a set of standardized operating procedures and identification criteria to ensure that the measured It can truly reflect the minimum rupture strength of salt rock or brine layers under the current well depth and stress conditions. In the specific implementation process, the test is usually carried out in an open well section or a bare hole section below the casing shoe, in order to avoid the constraint interference of the casing on the rupture behavior of the formation. In order to eliminate the coupling effect with other layers, especially when there are heterogeneous lithological stratification or fault zones above and below the brine layer, it is necessary to give priority to selecting brine layers with good sealing properties and representativeness in geological structures as test objects. In terms of equipment layout, the system uses bridge plugs or expandable packers to completely isolate the target test section, thereby effectively preventing the injected fluid from flowing to adjacent layers and improving the independence and accuracy of the test.

[0031] During the test operation, drilling fluid or fracturing fluid is slowly injected into the isolated well section, and the pressure-time response curve of the test section is recorded in real time by a high-precision pressure sensing system. The injection rate must be strictly controlled during the pressure injection process to avoid pseudo-cracks caused by too fast a rate or inelastic strain response before the fracture pressure is reached. As the pressure gradually increases, the fracture closure stress in the formation is overcome, and the initial fracture surface begins to open under the drive of shear stress or tensile stress. At this time, the pressure-time curve will show an obvious inflection point: the original stable linear rising pressure trend will suddenly slow down or stagnate, and even slightly decrease in some cases; at the same time, the pressure relief curve also shows a mutation feature, indicating that the fluid begins to leak into the formed fracture system in large quantities. This inflection point is the formation fracture pressure in the defined sense. , its physical meaning is the turning point where the formation changes from an elastic state to an inelastic fracture state. Since saltwater layers are mostly mixed behaviors of strong plasticity and weak brittleness, their fracture process often does not manifest as a violent fracture, but slowly opens in the form of creep cracks or strain instability in stress concentration areas. Therefore, the identification of this pressure inflection point places higher requirements on sensor sensitivity and data analysis algorithms. This system mathematically determines the slope change of the real-time curve by embedding a differential fluctuation detection algorithm and a fitting regression function, which avoids human subjective judgment errors while enhancing the test accuracy and improving the automation level of fracture pressure identification.

[0032] Furthermore, the osmotic pressure model is: ; in, is the osmotic pressure of the saline layer; is the reference pressure, which is 10.1MPa; It is the crystallinity term of salt water, which indicates the ratio between the dissolved state and the crystalline state in salt water under certain temperature and pressure conditions. It determines whether the salt exists stably in the solution in an ionic state or has begun to crystallize out. The higher the crystallinity, the more salt exists in the solid form, resulting in a lower solution density. When the density of salt water is higher than the standard water density, there is more dissolved salt and the crystallinity is low. When the density of salt water is close to or lower than the standard water density, it means that there is less dissolved salt or some salt has crystallized. The ratio approaches 1 or is less than 1, and the osmotic pressure decreases. is the gas constant, with a value of 8.314 and a unit of ; is the reference temperature, the value is 298.15, the unit is K; is the crystallinity sensitivity coefficient.

[0033] During the drilling operation of high-pressure saline layers, there is a significant material exchange and seepage phenomenon between the drilling fluid and the formation brine. Due to the high concentration of salt, large temperature gradient, and complex rock pore structure, the permeability behavior of the saline layer no longer conforms to the linear flow law controlled by a single Darcy's law, but exhibits a typical coupled nonlinear migration mechanism. In order to construct an osmotic pressure expression that can be used for drilling fluid density feedback regulation, it is first necessary to derive the interface pressure difference driven by dissolution behavior based on the solute migration equation and thermodynamic potential energy difference, and then further map it to the macroscopic response structure of actual formation compaction control.

[0034] The first step is to start from the conservation of interface diffusion mass and assume that there is a continuous salt migration process between the drilling fluid and the brine layer in a certain period of time, and control the solute flux on the microelement interface It can be extended from the classic Fick's law: ; in is the diffusion coefficient, Represents the concentration gradient of salt between the well wall and the pores of the brine layer. Since the migration of salt in the high-pressure brine layer is limited by the chemical reaction rate and the interface exchange resistance, the concentration gradient is not used directly here, but the migration rate is re-expressed as: ; in is the reaction rate constant for salt dissolution, Indicates the saturation concentration of salt at the current temperature. is the current formation salt concentration. This expression reflects the net dissolution rate of salt migrating into the drilling fluid with the saturated solution as the upper limit.

[0035] The second step is to consider that the salt dissolution reaction is driven by thermodynamics. Under non-isothermal conditions, the dissolution rate needs to consider the Arrhenius form controlled by activation energy, that is: ; in is the activation energy of salt, is the gas constant, is the absolute temperature. To construct the complete expression, this term is introduced into the total flux, and we have: ; Combined with the molar volume of the salt , the migration rate can be converted into the mechanical effect per unit volume, that is, a volume conversion factor is introduced , the osmotic pressure increment caused by salt migration per unit area of ​​the interface is obtained. Since the local concentration change induced by solute migration will affect the microscopic osmotic pressure tensor, the first-order linear approximation can be used to construct the pressure response under the steady-state approximation: ; However, the above terms fail to reflect the nonlinear correction of temperature disturbance to the pressure field, so the thermal expansion response term is introduced , which is used to correct the effect of mechanical expansion under non-isothermal conditions. This term is based on the assumption that the closer the system temperature is to the reference temperature The smaller the expansion potential is, the stronger the loosening effect of the structure is when it is far away from the reference state, thereby increasing the osmotic pressure.

[0036] The above multiple factors are integrated to construct the local osmotic pressure response: ; Note that the first term in this expression uses the maximum solubility The reason for replacing saturation concentration is that the maximum solubility limit is often used for estimation in actual drilling process. It reflects the rate deviation in the actual dissolution process, and the two constitute an approximate net solute change gradient.

[0037] The third step is to map the microscopic pressure response to the macroscopic wellbore scale and introduce the pore compaction function in the mechanical modeling: ; This function describes the compaction behavior between the top of the saltwater layer and the current depth, expressing the exponential increase in pore pressure with increasing depth. Characterizes compaction sensitivity. The larger the value, the easier the formation is to compact and the more obvious the change in osmotic pressure gradient is.

[0038] Aggregate all sub-items to build a complete osmotic pressure model: Take the reference pressure As a benchmark; introduce brine crystallinity control , simulating the inhibitory effect of the crystal precipitation state on the pressure field; and then multiplied by the interface dissolution contribution term, that is, ; Then introduce the dissolution dynamics term and thermal disturbance term to comprehensively express it as ; Finally, multiply by the depth-dependent formation compaction response term The final osmotic pressure is a function of all the above physical mechanisms. It is not only a pressure response, but also a manifestation of fluid-solid coupling of salt water layers under high temperature and high pressure chemical action. Especially when the salt tends to be saturated or crystallized, the model can accurately reflect the local permeability blockage induced by crystal precipitation; under high temperature and high solubility conditions, the model can predict the trend of forward osmotic pressure enhancement induced by the continuous entry of salt into the drilling fluid. During system operation, the parameters of all sub-items are dynamically updated in real time through the data acquisition module, making the model a continuously evolving time function. Its output value It will be transmitted to the drilling fluid density adjustment module and the safety pressure window calculation module to form a control mechanism to ensure that the drilling fluid always meets the pressure balance conditions and realizes the coordinated control of wellbore stability and well control risks.

[0039] Furthermore, the crystallinity sensitivity coefficient The value of ; is the absolute value operator.

[0040] Terms included in the osmotic pressure model It is called the "crystallinity term". Its physical meaning is that it reflects the relative proportion between the dissolved state and the crystalline state in the brine system according to the ratio of the density of brine to the density of pure water. The larger the ratio, the more the salt is in a dissolved state and the higher the permeability. When the ratio is close to 1 or less than 1, it means that the salt tends to crystallize or has precipitated in large quantities, resulting in a decrease in the density of the solution and a decrease in the permeability. The actual sensitivity of this crystallinity term is different under different formation compaction conditions, so a dynamically adjusted exponential coefficient must be introduced. To give it adaptive responsiveness.

[0041] In high pressure saline formations, the compaction index It is an empirical factor that describes the nonlinear decrease in porosity of a stratum with increasing burial depth. It is considered to be an idealized situation in which the formation is in a linear compaction state, in which the pore structure has good uniformity and the compressive stress is linearly related to the depth. When , it means that the pore compressibility of the formation is higher and the rock is easier to be compacted; on the contrary, When , it means that the pore structure is more rigid, the compressive resistance is enhanced, and the permeability of the formation is relatively stable.

[0042] Set the crystallinity sensitivity coefficient to The mathematical basis of is derived from the above physical behavior regulation needs. When the layer compaction index is far away from 1, that is, When it tends to be larger, it means that the current formation is in an extreme state of strong or weak compaction, the permeability structure is sensitive, and the crystallization / dissolution state of the brine has a more significant impact on the overall permeability pressure. At this time, the effect of the crystallinity term must be amplified so that the model can quickly respond to small changes in the formation structure. When it approaches 1, the compaction state of the formation is close to the linear ideal model, the pore change is stable, and the crystal state has a weak effect on the permeability behavior. As it approaches 0, the regulating effect of the crystallinity term on the osmotic pressure is naturally weakened, thereby avoiding the risk of over-response or misjudgment of the model.

[0043] In addition, the absolute value operation is taken instead of retaining the sign to ensure that The response intensity is kept consistent in both formation characteristics below or above 1, that is, whether it is overcompaction (enhanced rigidity) or undercompaction (soft and easy to compress), as long as it deviates from the ideal compaction state, the weight of the influence of crystallinity change on permeability pressure should be increased. This setting can be regarded as an asymmetric sensitivity control strategy. Through nonlinear adjustment of parameters, the model is adaptable to extreme well section environments and avoids overfitting in stable sections.

[0044] Therefore, from the perspective of modeling logic, It is a mechanism that dynamically weights the sensitivity of crystallinity based on compaction behavior. Its essence is to introduce physical geological characteristics into the parameter index space to achieve a quantitative expression of the coupling relationship between the crystallinity response intensity and the formation structure. In engineering practice, this parameter does not need to be set manually, but can be dynamically generated based on the compaction index obtained by real-time measurement or geological logging, with good adaptability and field operability. Finally, The setting not only enhances the nonlinear adjustment capability of the permeability pressure model, but also constitutes one of the mathematical supports for the "density optimization control strategy dominated by formation physical behavior" advocated by the present invention, reflecting the complex regulation mechanism of this system driven by the three factors of mechanics, thermodynamics and material migration.

[0045] Furthermore, the optimal drilling fluid density for: ; in, Maximum density increase due to salt, in kg / m³.

[0046] First, starting from the basic composition of drilling fluid density, we assume It represents the initial density of the basic water-based drilling fluid without the addition of salt. This is a known constant and is the benchmark starting point of the entire density model. The increase in the density of the drilling fluid mainly comes from the dissolution of salt. As the solute concentration in the solution increases, the density increases accordingly, and when the maximum solubility is reached, the density increases accordingly. After that, it tends to saturation, and the density no longer increases significantly. Therefore, an upper limit parameter of density increment is introduced , which is defined as the increase in the density of the drilling fluid relative to the base density when it is fully saturated with salt, that is: ; This is the theoretical upper limit of the density control process. In order to establish a nonlinear growth relationship between salt concentration and density, this system uses a densification factor based on exponential decay, namely: ; The derivation logic of this term can be explained by the diffusion-saturation kinetic framework. Assume that the higher the salt concentration dissolved into the drilling fluid per unit time (i.e. The larger the value, the greater the osmotic pressure of the saltwater layer. The greater the driving effect, the faster the density rises. However, this growth process is limited by the maximum solubility. , and the product of pressure and concentration must be normalized in some way, thus introducing a reference pressure Dimension matching and mathematical balance are performed. The entire exponential expression simulates: When it is small, the density increase is not obvious; when the value continues to increase, the exponential decay term approaches zero, so the overall density term approaches Theoretical upper limit of , showing saturation behavior. This form is similar to the logistic growth model, but is more suitable for irreversible material addition processes.

[0047] Next, consider the thermal disturbance term , which is derived from the typical inverse response of liquid density to temperature. At high temperatures, the liquid volume expands and the density decreases. In the brine system, the addition of salt will also cause structural hydrolysis and complexation reactions, resulting in more complex density fluctuations. In order to simplify the modeling without losing accuracy, the linear expansion coefficient is introduced , whose unit is K⁻¹, is usually taken from the range of thermal expansion coefficient of saline water (about 3×10⁻ 4 to 5×10⁻ 4 ). This term simulates the trend of density decreasing with increasing temperature. However, in this model, in order to maintain the relative conservatism of density estimation (i.e., at high temperature, it should be more inclined to increase density to prevent the wellbore pressure from decreasing), it is placed in the multiplication factor of the overall density expression instead of the subtraction term, so that the thermal disturbance term adjusts the intensity of the densification coefficient instead of directly acting on the basic density.

[0048] At this point, the above items are integrated to obtain the expression of the optimal drilling fluid density: ; This expression has a clear correspondence with the physical mechanism: the first part is the static basic density; the second part is the nonlinear densification term driven by salt osmotic pressure; the third part is the thermal response adjustment term, which performs temperature correction on the density response amplitude. The advantage of this model is that it converts the drilling fluid density from an empirical set value into a dynamic generated amount, so that the density adjustment can respond to changes in the downhole geological thermal state, permeability behavior and chemical migration rate in real time. In the actual control system, the input parameters of the model all come from the front data acquisition module. Combined with the digital well control platform, it can realize automatic adjustment and intelligent feedback of density, thereby maintaining the stability of the wellbore while avoiding the risk of leakage caused by excessive density and blowout caused by too low density.

[0049] Furthermore, the maximum density increase contributed by salt is Indicates that when there is no salt in the drilling fluid, the drilling fluid density is the basic density of the water-based drilling fluid ; As salt is added, the density of the drilling fluid gradually increases. Assuming that the salt reaches its maximum solubility and completely dissolved, the drilling fluid density will reach a limit value ,at this time: .

[0050] In the high-pressure salt water layer drilling fluid density optimization and pressure control system proposed by the present invention, the maximum density increment contributed by salt is The definition of is not just an empirical correction term, but the core physical parameter in the drilling fluid density model. Its derivation process fully reflects the regulatory effect of the solute-solvent interaction in the brine system on the overall density behavior of the fluid. The establishment of this parameter is based on the nonlinear evolution law of material concentration-density in the process of drilling fluid from salt-free state (basic density) to salt saturation state (limit density), which provides a measurable and quantifiable dynamic range for density regulation.

[0051] First, define the basic density of the drilling fluid It refers to the density of the drilling fluid when no soluble salt is added to the drilling fluid formula, which is composed only of water or other non-salt base fluids. For conventional water-based drilling fluids, this value is usually kg / m^3, which may be slightly higher depending on specific additives (such as clay, organic polymers, etc.). This density is the baseline and reference starting point for all density control strategies.

[0052] As salt is gradually added, the density of the drilling fluid begins to increase. This phenomenon comes from the fact that after the salt dissolves in water, its solute particles are embedded in the network structure of water molecules, which increases the mass contained in a unit volume and leads to an increase in the overall mass. It should be emphasized that this increase is not a linear behavior, but is affected by multiple factors such as salt type, solution concentration, temperature and ion interaction. Especially when the concentration gradually approaches the maximum solubility During the process, the brine system gradually transitions from a dilute solution to a concentrated solution state. The intermolecular repulsion, ion association, solvation effect, etc. will produce complex interferences on the volume behavior and density changes.

[0053] When the drilling fluid density reaches the state corresponding to the maximum solubility, that is, all salts are completely dissolved under given temperature and pressure conditions, the solution density reaches its physical limit value, which is recorded as The density in this state is usually determined by experiment or calculated by equation of state. For example, for saturated sodium chloride solution, the density at room temperature can reach about 1200 kg / m³, while for heavy salts such as calcium chloride or barium chloride, the density can even exceed 1500 kg / m³. These differences depend on the molar mass, solubility and ionic strength of the salt itself.

[0054] In order to quantitatively control the density growth from the basic state to the saturation state, it is defined as: ; This expression is the upper limit of the salt contribution intensity in the drilling fluid density model, and can also be understood as the maximum achievable value of the "salt-density response window". It sets the saturation value of the nonlinear growth term in the optimal density calculation formula. That is, in the formula ; In the formula, It determines the theoretical extreme value that the entire density increment can reach when the osmotic pressure and salt concentration approach the upper limit. This setting not only ensures the physical rationality of the model, but also provides boundary constraints for engineering control to prevent the density estimate from exceeding the reasonable range.

[0055] It is worth noting that in actual engineering applications, It is not necessary to obtain it through field experiments every time, but it can be obtained by consulting standard physical data manuals or computational chemical simulation methods based on the known physical properties and proportion concentrations of the salts used in the drilling fluid. For well sections with higher accuracy requirements, it can also be directly measured by preparing saturated solutions in the laboratory. and , which can accurately give , thus providing the core input parameters for the density model.

[0056] Furthermore, safe drilling pressure for: .

[0057] Safe drilling pressure window in high-pressure saltwater formation drilling fluid density optimization and pressure control system The calculation of is the key link to achieve real-time pressure regulation and dynamic avoidance of well control risks. The upper limit of the safe drilling pressure is controlled by the formation fracture pressure, and the lower limit is determined by the mechanical balance formed by the formation seepage pressure and the static pressure gradient of the drilling fluid. The given formula not only takes into account the traditional geostress difference, but also couples the rock shear properties, the dynamic seepage behavior of the drilling fluid, the pore scale effect and the rheological parameters. It is a composite expression derived under the collaborative modeling of multi-physics fields. During drilling operations, the total effective stress borne by the well wall comes from three parts: the static pressure of the well fluid (determined by the density of the drilling fluid), the seepage stress (driven by the pressure difference between the formation and the drilling fluid), and the geostress distribution (determined by the geological structure, compaction and friction, etc.). In order to avoid well wall rupture or fluid instability, density control is required between the two limits, namely: ; in, is the osmotic pressure, is the net shear stress expression of the formation acting on the wellbore wall, is the drilling fluid column pressure (actual density control value), and It is the formation fracture pressure, which determines the upper limit of pressure control. Therefore, the safe pressure window is defined as the pressure range that the drilling fluid can adjust. Its calculation is essentially an algebraic operation on both ends of the above formula.

[0058] set up represents the allowable drilling fluid pressure adjustment range, then: ; To further express , which needs to be converted into the local shear stress term of the wellbore, and its derivation can be traced back to the Coulomb-Moore failure criterion. In salt rock, a typical weakly cemented plastic formation, the internal friction angle It is a critical parameter for measuring the occurrence of shear slip. According to the limit equilibrium theory, the maximum shear strength of the formation before rupture It can be expressed as: ; This formula is derived from the shear stress-normal stress coupling expression in the Coulomb criterion, taking into account the fracture inducement caused by the combined effects of gravity field and friction slip. This stress term actually reflects the minimum effective support strength that the rock mass can withstand without shear failure. Therefore, substituting it into the above formula, we get: ; At this point, the first part of the pressure window has been established, which reflects the density adjustment range under the static geomechanical field.

[0059] In the actual drilling process, the above-mentioned ground stress difference alone cannot fully determine whether the density adjustment is safe and reliable. Because when the drilling fluid enters the micro-cracks or pores, its movement will be restricted by significant viscosity resistance and pore structure, resulting in pressure attenuation along the radial direction or the axial direction of the wellbore, forming the so-called local pressure drop. Therefore, this fluid dynamics effect must be corrected in the model.

[0060] Starting from the seepage behavior of drilling fluid through porous media (i.e., formation), let the density of drilling fluid be , the acceleration due to gravity is , then its static pressure is at the bottom depth It can be expressed as: ; This is a standard hydrostatic expression. However, due to the microporous structure between the wellbore and the formation, the drilling fluid is not evenly distributed, but non-Newtonian viscous flow occurs in the pores. This flow process is affected by the rheological properties of the drilling fluid itself, the pore size and permeability of the formation. For this reason, the Poiseuille flow model controlled by the micropore diameter is referred to to establish the pressure drop term per unit volume: ; The derivation process of this expression is as follows: Assume that the formation is a permeable medium composed of an equivalent circular tube network, and the total pore area is given by the average pore size Characterization; Permeability Indicates the volume flow rate of drilling fluid under unit pressure difference; drilling fluid viscosity Inhibit flow capacity and form seepage resistance; flow rate is the annular circulation velocity of the drilling fluid, which is an important factor in the pressure propagation rate. The quadratic term control reflects the nonlinear enhancement effect of flow channel size on pressure drop.

[0061] The pressure drop term is finally expressed as the reduction of the pressure window per unit volume, that is: ; Finally, the complete pressure window expression can be obtained: ; The complete formula consists of two parts: the first part (the term in curly brackets) reflects the theoretical density adjustment range under geomechanical control; the second part (the product correction term) reflects the effective pressure reduction under the actual seepage state of the drilling fluid. This structural design is physically reasonable: when the drilling fluid flow rate is large, the pore size is small, or the viscosity is low, the pressure drop term becomes larger, which means that even if the apparent density meets the requirements, the actual pressure supporting the well wall will be reduced due to seepage loss, so the density must be increased or the flow rate must be reduced to compensate; conversely, when the viscosity is high or the pore size is large, the pressure drop is small and the density requirement can be moderately relaxed. This dynamic correction mechanism significantly improves the system's adaptability in complex well sections (such as broken salt rock, dissolved salt layers, etc.). In order to ensure that the formula can be widely applied to different geological well sections, the following parameters are set with actual engineering upper and lower limits in the derivation: : Lithology can be obtained through core shear test; : Set according to the density of salt rock; : Micrometer to sub-millimeter; : Covering water base to polymer drilling fluid; Conventional drilling circulation speed. Starting from the mechanical balance of the wellbore, this formula establishes the shear stability condition based on the friction angle, and derives the seepage pressure drop correction term from the seepage mechanics, and finally forms a full physical modeling formula for safe drilling pressure. This formula integrates geomechanics, pore seepage, fluid dynamics and rheological behavior. It not only has good theoretical explanation, but is also suitable for density regulation control in actual drilling projects. It is one of the theoretical cores of the present invention to construct a density-pressure coupling control system, ensuring the engineering safety and real-time intelligence of density response in the high-pressure salt water layer drilling environment.

[0062] The present invention is not limited to the above-mentioned specific embodiments, but extends to any new features or any new combination disclosed in this specification, as well as any new method or process steps or any new combination disclosed.

Claims

1. A high-pressure saltwater layer drilling fluid density optimization and pressure control system, characterized in that: include: The data acquisition part is used to acquire saltwater layer data and drilling data; The osmotic pressure model part is used to establish an osmotic pressure model that takes into account the brine crystallinity and temperature and pressure effects, and obtain the osmotic pressure of the brine layer; The drilling fluid density analysis and control part is used to evaluate the effect of salt solubility in the brine layer on the drilling fluid density, establish a coupling model between the brine layer solubility and the drilling fluid density, and obtain the optimal drilling fluid density to control the drilling fluid density; The safety drilling pressure analysis and control part is used to calculate the safety drilling pressure according to the formation fracture pressure and the optimal drilling fluid density, and to set the safety drilling pressure window according to the safety drilling pressure to control the drilling pressure.

2. The high-pressure saltwater formation drilling fluid density optimization and pressure control system according to claim 1, characterized in that: The saltwater layer data include: saltwater layer fluid density , unit is kg / m³; activation energy of brine , in J / mol; permeability of saline layer , in m²; molar volume of salt , in m³ / mol; maximum salt solubility , in mol / L; contact area between drilling fluid and salt water layer , in m²; salt dissolution rate constant , unit is m / s; salt concentration change rate , the unit is ; is the time, in seconds; the salt concentration of the saline layer , unit is mol / L; thermal expansion coefficient of salt water layer, value range is arrive , the unit is .

3. The high-pressure saltwater layer drilling fluid density optimization and pressure control system according to claim 2, characterized in that: Drilling data includes: Current depth , in m; depth of top of saline layer , unit is m; formation temperature , unit is K; stratum thickness , unit is m; formation compaction index , the value range is 0.7 to 1.3; the basic density of water-based drilling fluid , unit is kg / m³; internal friction angle of salt rock , unit is rad; true vertical depth , unit is m; circulation flow rate , in m / s; average pore diameter , unit is m; drilling fluid viscosity , unit is Pa·s.

4. The high-pressure saltwater formation drilling fluid density optimization and pressure control system according to claim 3, characterized in that: Formation fracture pressure The unit is MPa and is determined through micro-crack test. The specific steps include: conducting the test below the casing shoe, in an open well section or a bare hole section, selecting a layer that does not interfere with other layers, using a bridge plug or a packer to isolate the test section to prevent liquid leakage to other layers, injecting drilling fluid or fracturing fluid into the test section, gradually pressurizing until the initial crack opens, and recording the pressure-time curve. After the pressure reaches a certain inflection point, it no longer rises linearly, and the liquid suddenly leaks into the formation and forms cracks. This inflection point is the formation fracture pressure, which is manifested as: the pressure stops rising instantly or drops slightly, and the pressure relief curve shows a sudden change.

5. The high-pressure saltwater formation drilling fluid density optimization and pressure control system according to claim 4, characterized in that: The osmotic pressure model is: ； in, is the osmotic pressure of the saline layer; is the reference pressure, which is 10.1MPa; It is the crystallinity term of salt water, which indicates the ratio between the dissolved state and the crystalline state in salt water under certain temperature and pressure conditions. It determines whether the salt exists stably in the solution in an ionic state or has begun to crystallize out. The higher the crystallinity, the more salt exists in the solid form, resulting in a lower solution density. When the density of salt water is higher than the standard water density, there is more dissolved salt and the crystallinity is low. When the density of salt water is close to or lower than the standard water density, it means that there is less dissolved salt or some salt has crystallized. The ratio approaches 1 or is less than 1, and the osmotic pressure decreases. is the gas constant, with a value of 8.314 and a unit of ; is the reference temperature, the value is 298.15, the unit is K; is the crystallinity sensitivity coefficient.

6. The high-pressure saltwater formation drilling fluid density optimization and pressure control system according to claim 5, characterized in that: Crystallinity sensitivity coefficient The value of ; is the absolute value operator.

7. The high-pressure saltwater formation drilling fluid density optimization and pressure control system according to claim 6, characterized in that: Optimum drilling fluid density for: ； in, Maximum density increase due to salt, in kg / m³.

8. The high-pressure saltwater formation drilling fluid density optimization and pressure control system according to claim 7, characterized in that: Maximum density increase contributed by salt Indicates that when there is no salt in the drilling fluid, the drilling fluid density is the basic density of the water-based drilling fluid ; As salt is added, the density of the drilling fluid gradually increases. Assuming that the salt reaches its maximum solubility and completely dissolved, the drilling fluid density will reach a limit value ,at this time: 。 9. The high-pressure saltwater formation drilling fluid density optimization and pressure control system according to claim 8, characterized in that: Safe drilling pressure for: 。

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