Water-based drilling fluid method and system for improving wellbore stability and apparatus

Abstract

Water-based drilling fluid improves well wall stability method and system and equipment, including the following steps: fine evaluation of formation lithology mineral component is used to conventional well logging curve;Obtain rock mechanics parameters under complex lithology background;According to the rock mechanics parameters, the present ground stress value is obtained by using the well wall fracture track inversion method;Collapse pressure calculation under the action of mud shale mechanics-chemical coupling is constructed;Drilling fluid safety mud density window determination: the lower limit and upper limit value of the window are determined, the lower limit of the window is the formation collapse pressure, and the upper limit is the formation leakage pressure;On the basis of rock mechanics parameters, ground stress, formation component content, determine the drilling fluid performance.The present application combines the analysis results of mineral component, analyzes the rheological property, thermal stability, inhibition and sealing property of different formulations of water-based drilling fluid through experiment, so as to formulate the drilling fluid formulation for different formations, finally design the drilling fluid density and performance formulation, improve the well wall stability of water-based drilling fluid, and support safe and rapid drilling.

Description

Technical Field

[0001] This invention belongs to the field of deep-earth oil and gas resource development, and specifically relates to methods, systems and equipment for improving wellbore stability with water-based drilling fluids. Background Technology

[0002] In deep-ground oil and gas well drilling, wellbore instability occurs to varying degrees, leading to significant losses of manpower, resources, and finances, and even catastrophic accidents. Therefore, maintaining wellbore stability during drilling is a crucial topic in drilling engineering geology research. In recent years, due to the encounter with ultra-deep and complex formations, including complex lithology, geostress, and fractures, wellbore instability has become increasingly prominent. Drilling engineers have developed water-based and oil-based drilling fluids with different properties. Oil-based drilling fluids, in particular, have played a role in overcoming wellbore instability and have been widely adopted. However, the widespread use of oil-based drilling fluids has brought new problems, such as high cost, significant environmental pollution, toxicity, and impact on logging oil and gas response prediction and cementing casing cleaning. This has led drilling engineers and oil and gas well owners to reconsider the use of water-based drilling fluids. However, the lack of systematic research on the application of water-based drilling fluids from the perspectives of geological analysis, mechanical research, and mechanochemical coupling has resulted in a long-standing misunderstanding among drilling engineers regarding the effectiveness of water-based drilling fluids in suppressing wellbore instability. They believe that water-based drilling fluids are less effective than water-based drilling fluids, which has limited their application.

[0003] Among existing methods for improving wellbore stability, oil-based drilling fluids present several significant problems, specifically: ① High cost, 3-10 times higher than water-based drilling fluids; ② Difficulty in treating drilling fluid waste, classified as hazardous waste, with high transportation requirements and costs; ③ Significant environmental impact, causing substantial pollution to forests, rivers, mountains, and deserts; ④ High toxicity, containing a large amount of aromatic hydrocarbons in its formulation, toxic to humans and animals; ⑤ Prone to gas dissolution during drilling in gas-bearing formations, inducing blowouts and other disasters; ⑥ Significant impact on gas logging, potentially leading to misjudgments of oil and gas shows; ⑦ Difficulty in cleaning the wellbore and casing during cementing, difficulty in removing filter cake, incomplete evaluation methods for pre-flush fluid, severe fluid contact contamination, and low displacement efficiency.

[0004] Research on improving wellbore stability using water-based drilling fluids falls into two categories: one focuses on wellbore instability mechanisms and theoretical predictions, primarily represented by academic research; the other focuses on water-based drilling fluid formulation research, primarily represented by the drilling engineering industry. These studies suffer from limitations in scope, lack comprehensive consideration of geological conditions, and have significant limitations in application, resulting in poor generalizability. Furthermore, no complete method has been established for improving wellbore stability using water-based drilling fluids, and the results of any single research method cannot be directly applied to drilling engineering.

[0005] Overall, the above studies are all one-sided, and the various studies are relatively independent, and cannot completely solve the problem of improving wellbore stability with water-based drilling fluids. Summary of the Invention

[0006] The purpose of this invention is to provide a method, system, and equipment for improving wellbore stability with water-based drilling fluids, so as to solve the above-mentioned problems.

[0007] To achieve the above objectives, the present invention adopts the following technical solution:

[0008] A method for improving wellbore stability using water-based drilling fluids includes the following steps:

[0009] Utilize conventional well logging curves to finely evaluate the lithological and mineral composition of formations;

[0010] Obtain rock mechanical parameters under complex lithological backgrounds;

[0011] The current geostress value is obtained by using the wellbore fracture trajectory inversion method based on rock mechanics parameters;

[0012] Based on the stratigraphic lithology and mineral composition, the relationship between mineral component content and water-based mud filtrate intrusion was established, and a calculation method for collapse pressure under the mechanical-chemical coupling effect of mudstone and shale was constructed.

[0013] Determining the safe mud density window for drilling fluid: Clearly define the lower and upper limits of the window. The lower limit of the window is the formation collapse pressure, and the upper limit is the formation leakage pressure.

[0014] Based on rock mechanics parameters, geostress, and formation component content, the drilling fluid properties are determined.

[0015] Furthermore, the evaluation of stratigraphic lithology and mineral composition specifically includes:

[0016] Based on the logging cuttings repositioning data, the formation lithology was determined, and the mineral composition was calculated using the volumetric theory model.

[0017] Calculation of clay content:

[0018]

[0019]

[0020] In the formula: GR is the natural gamma of the logging curve, in units of Api; GRmin and GRmax are the minimum and maximum natural gamma values, respectively, in units of Api; IGR is the clay content index, in units of dimensionless; GCUR is the Hillch index, in units of dimensionless; VCL is the clay content, in units of dimensionless.

[0021] Porosity calculation:

[0022]

[0023] In the formula:

[0024] PIGN stands for porosity, unit: dimensionless; Δt is the longitudinal wave measurement time difference, unit: µs / ft; Δt ma The time difference of the rock skeleton, in µs / ft; Δt f Δtsh is the fluid transit time, in µs / ft; cp is the compaction correction factor, in dimensionless form; Δtsh is the mudstone skeleton transit time, in µs / ft.

[0025] Modified methods for evaluating mineral groups:

[0026] Pure salt content: GR < 30 Api, DT > 60 μS / ft, RT > 2000 Ω·m and PIGN = 0;

[0027] Pure ointment content: GR < 30 Api, DT < 60 μS / ft, RT > 2000 Ω·m and PIGN = 0;

[0028] Migration content: determined based on the volumetric theory model.

[0029] VQ = 1 - VCL - PIGN - VS - VH

[0030] In the formula:

[0031] DT is the measured sonic transit time, in µs / ft; VQ is the volumetric content of migmatite, in dimensionless units; VS is the volumetric content of salt rock, in dimensionless units; VH is the volumetric content of gypsum rock, in dimensionless units; RT is the formation resistivity, in Ω·m.

[0032] Furthermore, the acquisition of the rock's mechanical parameters:

[0033] Rock mechanics parameters related to wellbore stability include rock compressive strength, Poisson's ratio, Young's modulus, and tensile strength. Obtaining these parameters involves two steps: First, obtaining subsurface core samples for rock mechanics experiments to acquire static values ​​of these parameters. Then, using acoustic, density, and gamma data obtained from well logging, the dynamic values ​​of these parameters are calculated using theoretical formulas. Second, establishing the conversion relationship between dynamic and static values ​​of the rock mechanics parameters involves converting the dynamic values ​​obtained from well logging into static values ​​to obtain the parameters. Combined with rock composition analysis, the rock mechanics parameter values ​​under different lithological backgrounds are determined.

[0034] Further, the determination of geostress values:

[0035] The vertical stress (Sv) of the overlying strata was obtained using the density logging curve integration method. The range of the minimum horizontal principal stress (Sh) in the region was obtained using hydraulic fracturing. Formation pore pressure (Pp) data was obtained using the equivalent depth method and rock compressive strength data. Drilling fluid density data was obtained from actual drilling data. Wellbore collapse caused by stress release was identified from electrical imaging logging images, and collapse width data was read from the images. Stress polygons were constructed according to the slopes determined by different algorithms, and the compressive strength was marked in the stress polygons according to the matching relationship between formation compressive strength and stress. The stress value of the target well was obtained by using the various parameters obtained by the above methods and the relationships between the following parameters.

[0036] Further calculation of collapse pressure:

[0037] Using conventional well logging curves, the mineral composition profile of rocks is precisely evaluated. Based on the extraction of mineral component content, the relationship between mineral component content and water-based mud filtrate intrusion is established, and a method for calculating collapse pressure under the mechanical-chemical coupling effect of shale is constructed.

[0038] Equation for mud filtrate intrusion in shale formations:

[0039]

[0040] In the formula: W0: Initial water content of shale, in %; W s Saturated water content of mudstone and shale, in %; C f : Water absorption and diffusion coefficient of shale, related to mud properties, unit: cm2 / h; t: Formation soaking time of mud filtrate after well drilling, unit: h; x: Dimension of distance from well wall, unit: cm; W: Mud filtrate intrusion amount of shale, unit: %;

[0041] Establish the relationship between mineral component content and mud filtrate intrusion amount;

[0042] Substitute the relationship between clay content and mud filtrate intrusion amount into the formula for calculating stone mechanical parameters:

[0043] Quantitative calculation formula for Young's modulus under mechanical-chemical coupling of shale and mudstone:

[0044]

[0045] Quantitative formula for calculating Poisson's ratio under the mechanical-chemical coupling effect of shale:

[0046] v w =V a +V b *(a*vcl-b)

[0047] Quantitative calculation formula for cohesion under mechanical-chemical coupling of shale and mudstone:

[0048] Fc w =Ks*[(a*vcl-b)-W b ]

[0049] Quantitative calculation formula for the internal friction angle of shale under mechanical-chemical coupling:

[0050] φ w =φ a *[(a*vcl-b)-W b ]

[0051] In the above formula:

[0052] Ea, Eb, Va, Vb, φ a : Regional empirical coefficient, unit: dimensionless; Ks: coefficient, unit: dimensionless; Wb: initial water content increment, unit: %; vcl: mud content, unit: %; a, b: coefficients relating mud filtrate intrusion amount to mud content, unit: dimensionless;

[0053] Current quantitative calculation of horizontal geostress:

[0054] Quantitative calculation formula for maximum horizontal principal stress under mechanical-chemical coupling of shale and mudstone:

[0055]

[0056] Quantitative calculation formula for minimum horizontal principal stress under mechanical-chemical coupling of shale and mudstone:

[0057]

[0058] In the formula:

[0059] Tz: Vertical stress; unit: MPa; biot: Biot coefficient of rock parameter; unit: dimensionless; Pp: Formation pore pressure; unit: MPa; x, y: Tectonic strain coefficients along the direction of maximum horizontal principal stress and the direction of minimum principal stress, respectively; unit: dimensionless.

[0060] Quantitative calculation formula for collapse pressure under the mechanical-chemical coupling effect of shale:

[0061]

[0062]

[0063] In the formula:

[0064] a: Stress nonlinearity correction factor, unit: dimensionless.

[0065] Furthermore, determining the drilling fluid density window requires clarifying the lower and upper limits of the window. The lower limit of the window is the formation collapse pressure, and the upper limit is the formation leakage pressure. The formation collapse pressure considers two factors: one is the formation collapse pressure with mudstone and shale content, referred to as Wmin1, and the other is the formation collapse pressure when considering the weak surface of the formation, referred to as Wmin2 here.

[0066] Then compare Wmin1 and Wmin2, and the larger of the two is the lower limit of the drilling fluid safe mud density window;

[0067] The upper limit of the density window is the drilling fluid density at which the weak surface of the formation is opened by the drilling fluid during the drilling process, resulting in leakage. This density is called the critical opening pressure of the weak surface formation, which is referred to as Wmax.

[0068] Finally, the larger of Wmin1 and Wmin2 and Wmax are used as the basis for designing the drilling fluid safety density window.

[0069] Furthermore, the calculation of Wmax:

[0070] The stress on the natural crack surface is decomposed into effective normal stress σ along the normal direction of the crack surface and effective shear stress τ parallel to the crack surface direction.

[0071] σ=M 2 ×(SH-P p )+L 2 ×(Sv-P p )+N 2 (Sh-P p )

[0072]

[0073] The calculation method for the critical opening pressure of a natural fracture, i.e., the leakage pressure, is as follows:

[0074]

[0075] In the formula: L = cos(DIP)

[0076] M=|sin(DIP)×cos(AZIDIP-AZISH)|

[0077] N=|sin(DIP)×sin(AZIDIP-AZISH)|

[0078] SV: Vertical stress, unit: MPa; μ: Natural crack sliding friction coefficient, dimensionless; DIP: Natural crack dip angle, unit: °; AZIDIP: Natural crack dip direction, unit: °; AZISH: Principal stress orientation, unit: °.

[0079] Furthermore, the properties of water-based drilling fluids, including rheology, inhibition, plugging properties, and thermal stability, are determined through four processes. First, based on the rock mechanics, geostress, and formation component content established in the previous process, the relationship between drilling fluid density, mud activity, and wellbore collapse width is established. While determining the drilling fluid density, the wellbore collapse width is kept no higher than 30 degrees to determine the drilling fluid activity value. Then, according to the conversion relationship between activity and salinity, the activity is converted to salinity to determine the total salinity of the drilling fluid. Second, the content of the drilling fluid inhibition formulation is determined. When the clay content is higher than 50%, potassium chloride is added to 7%; when the clay content is 50%-20%, potassium chloride is added to 3-5%; when the clay content is lower than 20%, no potassium chloride is needed. Third, the solids content is determined. Based on the drilling flow rate, pump pressure, and tubing string structure parameters, the requirements for drilling fluid suspension capacity and wellbore cleaning capacity are determined, and the drilling fluid shear stress and viscosity parameters are calculated. The amount of solid material added to the drilling fluid is determined accordingly; fourth, based on the changes in formation temperature under different well depths, experiments are conducted to determine the thickening and deposition of drilling fluid at different temperatures, thereby determining the amount of high-temperature resistant material to be added to the drilling fluid.

[0080] Furthermore, water-based drilling fluid systems for improving wellbore stability include:

[0081] The formation lithology and mineral composition acquisition module is used to finely evaluate the formation lithology and mineral composition using conventional well logging curves;

[0082] The rock mechanics parameter acquisition module is used to acquire rock mechanics parameters under complex lithological backgrounds;

[0083] The geostress value acquisition module is used to obtain the current geostress value based on rock mechanics parameters using the wellbore fracture trajectory inversion method.

[0084] The collapse pressure calculation module is used to establish the relationship between mineral component content and water-based mud filtrate intrusion amount based on the lithological and mineral composition of the formation, and to construct the collapse pressure calculation under the mechanical-chemical coupling effect of mudstone and shale.

[0085] The drilling fluid safety mud density window determination module is used to determine the lower and upper limits of the window. The lower limit of the window is the formation collapse pressure, and the upper limit is the formation leakage pressure.

[0086] The drilling fluid performance determination module is used to determine drilling fluid performance based on rock mechanics parameters, geostress, and formation component content.

[0087] Furthermore, a computer device includes a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor, when executing the computer program, implements steps such as a method for improving wellbore stability using water-based drilling fluids.

[0088] Compared with the prior art, the present invention has the following technical effects:

[0089] This invention begins with a detailed analysis of the formation rock composition to clarify the mineral content of the formation. Then, it conducts a detailed evaluation of rock mechanical parameters to clarify the distribution characteristics of rock strength and elastic parameters. Further, it performs in-situ stress evaluation to obtain accurate in-situ stress data. Next, it conducts an analysis of the coupling effect of mechanics and chemistry to determine the minimum drilling fluid density value required to overcome formation collapse under the combined action of these two factors. Finally, it analyzes the presence of weak surfaces such as fractures and bedding in the formation, considering formation collapse and leakage at these weak surfaces, and determines the lower and upper limits of the drilling fluid density, thereby establishing a drilling fluid density window. Finally, based on the composition of the formation, it experimentally analyzes the rheological properties, thermal stability, inhibition, and plugging properties of water-based drilling fluids with different formulations, thereby developing drilling fluid formulations for different formations. Ultimately, this provides a basis for optimal drilling fluid density design and best formulation design.

[0090] This invention addresses the production requirements of water-based drilling fluids in maintaining wellbore stability. It begins with a detailed analysis of formation mineral components, establishing methods for evaluating rock mechanics and geostress parameters to preliminarily determine formation collapse pressure. Further research is conducted on the coupling effects of mechanics and chemistry, quantitatively analyzing the minimum density value required for water-based drilling fluids to maintain wellbore stability under mechanochemical conditions. Then, considering the leakage pressure when weak surfaces such as fractures, bedding planes, and sutures exist in the formation, this is used as the upper limit for drilling fluid density, thus determining the density window for water-based drilling fluids. Finally, combining the mineral component analysis results, experiments are conducted to analyze the rheological properties, thermal stability, inhibition, and plugging properties of water-based drilling fluids with different formulations. This allows for the development of drilling fluid formulations for different formations, ultimately designing drilling fluid density and performance formulations to improve wellbore stability and support safe and rapid drilling.

[0091] This invention identifies solutions for wellbore instability under the coupled mechanical, chemical, and production pressure differential conditions of water-based drilling fluid systems; addresses the evaluation of rock composition, rock mechanics, and geostress characteristic parameters under complex formation conditions; solves the quantitative evaluation of the interaction between water-based drilling fluids and formation chemical properties; resolves the problem of determining drilling stability and safe mud density windows under water-based drilling fluid conditions; solves the quantitative evaluation of the rheological properties, thermal stability, inhibition, and plugging properties of water-based drilling fluids with different formulations; and solves the quantitative design problem of density and performance parameters for maintaining wellbore stability in water-based drilling fluids with different mechanical properties. Attached Figure Description

[0092] Figure 1 This is a flowchart of the present invention.

[0093] Figure 2Stress polygon fabrication diagram;

[0094] Figure 3 The results of inversion of wellbore fracture tracks to realize current geostress;

[0095] Figure 4 Relationship between mineral composition and mud filtrate intrusion amount;

[0096] Figure 5 Design profile of relevant parameters for improving wellbore stability using water-based drilling fluid in a certain well; Detailed Implementation

[0097] The present invention will be further described below with reference to the accompanying drawings:

[0098] Please see Figures 1 to 5 ,

[0099] 1. A flexible method combining recording and measurement for precise evaluation of stratigraphic lithology and mineral composition.

[0100] Rock physical evaluation mainly selects rock mass models based on the mineral characteristics of the strata, and then obtains the mineral composition at different depths. This is the foundation of rock physical evaluation. Accurate mineral composition is very important for simulating compressive strength, collapse and fracture pressure, and is a fundamental part of engineering applications.

[0101] Mineral component extraction is mainly based on the response characteristics of conventional well logging curves to lithology. In the equation, the well logging curves are known variables, while the mineral components are unknown variables. The quantity and quality of the well logging curves determine the quantity and accuracy of mineral component extraction.

[0102] Conventional rock physics analysis models can be used to accurately evaluate the mineral composition of clastic and carbonate strata. However, in complex lithological assemblages, such as salt strata, conventional rock physics evaluation models cannot be used when the number of mineral components exceeds the measured curves due to limitations in measurement data (usually only natural gamma, sonic transit time, and resistivity curves are measured).

[0103] The present invention employs a modified approach combining recording and measurement:

[0104] First, the lithological characteristics of the formation are determined based on the logging cuttings relocation data.

[0105] For example, the main mineral components of salt rock strata are pure salt, pure gypsum, clay, and mixtures of salt, gypsum, and clay.

[0106] Secondly, the mineral composition is determined using the principle of volume theory model.

[0107] That is: 1 = V1 + V2 + V3 + ... + Vi (1)

[0108] In the formula: V1, V2, and V3 are the volume contents of minerals in the strata, in dimensionless units;

[0109] Vi is the formation pore volume, in dimensionless form.

[0110] There are only three actual measurement curves (known values) (natural gamma-ray - GR, sonic transit time - DT, deep lateral resistivity - RT), and the required mineral components include salt, gypsum, mudstone, and migmatite. In addition, there are five physical property curves, including porosity (unknown values).

[0111] Calculation of clay content:

[0112]

[0113]

[0114] In the formula:

[0115] GR is the natural gamma ray of the logging curve, in Api; GRmin and GRmax are the minimum and maximum natural gamma ray values, respectively, in Api; IGR is the clay content index, in dimensionless form.

[0116] GCUR is the Hill's index, in dimensionless units; VCL is the clay content, in dimensionless units.

[0117] Porosity calculation:

[0118]

[0119] In the formula:

[0120] PIGN stands for porosity, unit: dimensionless; Δt is the longitudinal wave measurement time difference, unit: µs / ft; Δt ma The time difference for the rock skeleton is expressed in µs / ft; Δt f Δtsh is the fluid transit time, unit: μs / ft; cp is the compaction correction factor, unit: dimensionless; Δtsh is the mudstone skeleton transit time, unit: μs / ft.

[0121] Modified method for evaluating mineral groups (three-curve constraint and porosity control):

[0122] Pure salt content: GR < 30 Api, DT > 60 μS / ft, RT > 2000 Ω·m and PIGN = 0;

[0123] Pure ointment content: GR < 30 Api, DT < 60 μS / ft, RT > 2000 Ω·m and PIGN = 0;

[0124] Migration content: Calculated using formula (1) based on the volume theory model.

[0125] VQ = 1 - VCL - PIGN - VS - VH

[0126] In the formula:

[0127] DT is the measured sonic transit time, in µs / ft; VQ is the volumetric content of migmatite, in dimensionless units; VS is the volumetric content of salt rock, in dimensionless units; VH is the volumetric content of gypsum rock, in dimensionless units; RT is the formation resistivity, in Ω·m.

[0128] 2. Evaluation of rock mechanical parameters in complex lithological settings

[0129] Rock mechanics parameters related to wellbore stability include rock compressive strength, Poisson's ratio, Young's modulus, and tensile strength. The evaluation of rock mechanics parameters involves two steps. The first step is to obtain underground rock cores for rock mechanics experiments to obtain the static values ​​of the above parameters. Then, using data such as sonic waves, density, and gamma rays obtained from well logging, the dynamic values ​​of the above parameters are calculated using theoretical formulas. The second step is to establish the conversion relationship between the dynamic and static values ​​of rock mechanics parameters, converting the dynamic values ​​obtained from well logging into static values ​​to obtain the above parameters. Combined with the rock composition analysis in section 1, the rock mechanics parameter values ​​under different lithological backgrounds are determined.

[0130] 3. Inversion of present-day geostress based on wellbore fracture traces

[0131] In this invention, the wellbore fracture trajectory inversion method is used to obtain the current geostress value. The implementation of this method requires three steps: First, the vertical stress (Sv) of the overlying strata is obtained using the density logging curve integration method, the range of the minimum horizontal principal stress (Sh) value in the region is obtained using the hydraulic fracturing method, the formation pore pressure (Pp) data is obtained using the equivalent depth method, the drilling fluid density data is obtained from the actual drilling data, and the rock compressive strength (C) data is obtained using the above (2); Second, the wellbore collapse caused by stress release is identified from the electrical imaging logging image, and the collapse width data is read from the image; Third,

[0132] according to Figure 2 The slopes determined by different algorithms are used to construct stress polygons. The compressive strength is marked in the stress polygons according to the matching relationship between the formation compressive strength and the stress. The stress value of the target well is obtained by using the various parameters obtained by the above method and the relationship between the following parameters. Figure 3 The small red box in the polygon on the right shows the range of the two horizontal principal stress values.

[0133]

[0134] 4. Quantitative determination of collapse pressure under the coupling effect of mechanics and chemistry

[0135] The mechanochemical coupling between water-based drilling fluids and rocks is widespread during drilling, resulting in changes to the rock's mechanical properties. For example, in sandstone and mudstone formations, when mudstone and shale come into contact with water-based drilling fluids, the mudstone and shale absorb water, altering the rock's mechanical parameters, reducing its strength and elastic modulus. In salt formations, the mineral composition and chemical properties of the rocks differ. When the salinity of the water-based drilling fluid used is lower than that of the salt water, the salt will dissolve, leading to changes in the rock's strength, stress, and other mechanical parameters. Under high temperature, high pressure, and high stress, this increases the creep rate of the salt, complicating the drilling process. Furthermore, the expansion stress generated by the absorption of water by gypsum and mudstone in salt formations can cause complex situations such as wellbore collapse, spalling, and borehole narrowing during drilling. This invention comprehensively considers a method for calculating collapse pressure based on the mechanochemical coupling effects under different lithologies, stresses, depths, and temperatures.

[0136] 1) In the first step, conventional logging curves are used to finely evaluate the rock mineral composition profile. Based on the extraction of mineral composition content, the relationship between mineral composition content and water-based mud filtrate intrusion is established, and a method for calculating collapse pressure under the mechanical-chemical coupling effect of shale is constructed.

[0137] ① Equation for mud filtrate intrusion in shale formations:

[0138]

[0139] In the formula:

[0140] This is the error compensation function;

[0141] W0: Initial water content of mudstone and shale, in %;

[0142] W s Saturated water content of mudstone and shale, in %;

[0143] C f The water absorption and diffusion coefficient of mudstone and shale is related to the properties of mud slurry, and the unit is cm2 / h.

[0144] t: Formation soaking time of drilling mud filtrate after well drilling, unit: h;

[0145] x: Distance from the well wall, in cm;

[0146] W: Intrusion amount of mud and shale mud filtrate, unit: %.

[0147] ②Establish the relationship between mineral component content and mud filtrate intrusion amount:

[0148] ③ Substitute the relationship between clay content and mud filtrate intrusion amount into the formula for calculating stone mechanical parameters:

[0149] Quantitative calculation formula for Young's modulus under mechanical-chemical coupling of shale and mudstone:

[0150]

[0151] Quantitative formula for calculating Poisson's ratio under the mechanical-chemical coupling effect of shale:

[0152] v w =V a +V b *(a*vcl-b) (3)

[0153] Quantitative calculation formula for cohesion under mechanical-chemical coupling of shale and mudstone:

[0154] Fc w =Ks*[(a*vcl-b)-W b (4)

[0155] Quantitative calculation formula for the internal friction angle of shale under mechanical-chemical coupling:

[0156] φ w =φ a *[(a*vcl-b)-W b (5)

[0157] In the above formula:

[0158] Ea, Eb, Va, Vb, φ a Regional empirical coefficient, unit: dimensionless;

[0159] Ks: Coefficient, unit: dimensionless;

[0160] Wb: Initial water cut increment, in %;

[0161] vcl: clay content, unit: %;

[0162] a, b: Coefficients relating mud filtrate intrusion amount to mud content, unit: dimensionless.

[0163] ④ Quantitative calculation of horizontal geostress today:

[0164] Quantitative calculation formula for maximum horizontal principal stress under mechanical-chemical coupling of shale and mudstone:

[0165]

[0166] Quantitative calculation formula for minimum horizontal principal stress under mechanical-chemical coupling of shale and mudstone:

[0167]

[0168] In the formula:

[0169] Tz: Vertical stress; Unit: MPa;

[0170] biot: Biot coefficient of rock parameter; unit: dimensionless;

[0171] Pp: Formation pore pressure; unit: MPa;

[0172] x, y: structural strain coefficients along the direction of maximum horizontal principal stress and the direction of minimum principal stress, respectively, in dimensionless units;

[0173] ⑤ Quantitative calculation formula for collapse pressure under the mechanical-chemical coupling effect of mudstone and shale:

[0174]

[0175]

[0176] In the formula:

[0177] a: Stress nonlinearity correction factor, unit: dimensionless;

[0178] 5. Determining the safe mud density window for drilling fluid

[0179] Determining the drilling fluid density window requires clarifying the lower and upper limits of the window. The lower limit of the window is the formation collapse pressure, and the upper limit is the formation leakage pressure. In this patent, the formation collapse pressure considers two factors. One is the formation collapse pressure calculated in step 4, taking into account the mudstone and shale content, which is referred to as Wmin1. The other is the formation collapse pressure when considering weak surfaces (referring to fractures, bedding, joints, sutures, etc.), which is referred to as Wmin2. The calculation method uses the following formula.

[0180] Then compare Wmin1 and Wmin2, and the larger of the two is the lower limit of the drilling fluid safe mud density window.

[0181] For the upper limit of the density window, which is the formation leakage pressure, this invention uses the drilling fluid density when the weak formation surface is opened by drilling fluid during drilling operations, resulting in leakage. This density is the critical opening pressure of the weak formation surface, referred to here as Wmax. The calculation process uses the following method:

[0182] The stress on the natural crack surface is decomposed into effective normal stress σ along the normal direction of the crack surface and effective shear stress τ parallel to the crack surface direction.

[0183] σ=M 2 ×(SH-P p )+L 2 ×(Sv-P p )+N2 (Sh-P p )

[0184]

[0185] The calculation method for the critical opening pressure of a natural fracture, i.e., the leakage pressure, is as follows:

[0186]

[0187] In the formula: L = cos(DIP)

[0188] M=|sin(DIP)×cos(AZIDIP-AZISH)|

[0189] N=|sin(DIP)×sin(AZIDIP-AZISH)|

[0190] SV: Vertical stress, unit: MPa;

[0191] μ: coefficient of sliding friction in natural cracks, dimensionless;

[0192] DIP: Natural fracture dip angle, unit: °;

[0193] AZIDIP: Natural tendency to crack, unit: °;

[0194] AZISH: Principal stress orientation, unit: °.

[0195] Finally, the larger of Wmin1 and Wmin2 and Wmax are used as the basis for designing the drilling fluid safety density window.

[0196] 6. Determination of the properties of water-based drilling fluid

[0197] The properties of water-based drilling fluids include rheology, inhibition, plugging properties, and thermal stability. Their determination involves four processes: First, based on the rock mechanics, geostress, and formation component content established in the previous process, the relationship between drilling fluid density, mud activity, and wellbore collapse width is established. While determining the drilling fluid density, the wellbore collapse width is kept no higher than 30 degrees to determine the drilling fluid activity value. Then, according to the conversion relationship between activity and salinity, the activity is converted to salinity to determine the total salinity of the drilling fluid. Second, the content of the drilling fluid inhibition formulation is determined. When the clay content is higher than 50%, potassium chloride is added to 7%. When the clay content is 50%-20%, potassium chloride is added to 3-5%; when the clay content is less than 20%, potassium chloride is not needed. Thirdly, the solid content is determined by considering parameters such as drilling flow rate, pump pressure, and tubing structure to determine the requirements for drilling fluid suspension capacity and wellbore cleaning capacity, and calculating parameters such as drilling fluid shear force and viscosity to determine the amount of solid material to be added to the drilling fluid. Fourthly, based on the changes in formation temperature under different well depths, experiments are conducted to determine the thickening and deposition of drilling fluid at different temperatures, thereby determining the amount of high-temperature resistant material to be added to the drilling fluid.

[0198] Example:

[0199] The implementation of the method of the present invention will be described in detail using Well A in Oilfield A as an example.

[0200] Step 1: Utilize conventional well logging curves to finely evaluate the formation lithology and mineral composition, such as... Figure 5 The second well contains sandstone, mudstone, gypsum, salt rock, and a mixed lithology of gypsum and salt rock.

[0201] Step 2: Evaluation of rock mechanical parameters in complex lithological settings Figure 5 The third parameter mainly consists of rock strength parameters.

[0202] Step 3: Invert the current geostress by tracking the fracture path in the wellbore, and obtain... Figure 5 The fourth stress in the equation includes vertical stress, the maximum horizontal principal stress, and the minimum horizontal principal stress.

[0203] Step 4: Quantitative determination of collapse pressure under the coupling effect of mechanics and chemistry. This step involves... Figure 5 The fifth and sixth steps in the calculation are the collapse pressure considering only mechanics and the collapse pressure considering the coupling of mechanics and chemistry, respectively.

[0204] Step 5: Determining the safe mud density window for drilling fluid. This process mainly utilizes... Figure 5 Using the fifth, sixth, and seventh data points, determine the mud density window according to the above method.

[0205] Step 6: Through experiments, determine the drilling fluid properties, design the drilling fluid formulation, and formulate a drilling fluid design scheme, such as... Figure 5 The eighth to twelfth indicators are mineralization degree, calcium ion content, potassium ion content, solid content, and high temperature and high pressure water loss index, respectively.

[0206] In another embodiment of the present invention, a water-based drilling fluid system for improving wellbore stability is provided, which can be used to implement the above-mentioned method for improving wellbore stability with water-based drilling fluid. Specifically, the system includes:

[0207] The formation lithology and mineral composition acquisition module is used to finely evaluate the formation lithology and mineral composition using conventional well logging curves;

[0208] The rock mechanics parameter acquisition module is used to acquire rock mechanics parameters under complex lithological backgrounds;

[0209] The geostress value acquisition module is used to obtain the current geostress value based on rock mechanics parameters using the wellbore fracture trajectory inversion method.

[0210] The collapse pressure calculation module is used to establish the relationship between mineral component content and water-based mud filtrate intrusion amount based on the lithological and mineral composition of the formation, and to construct the collapse pressure calculation under the mechanical-chemical coupling effect of mudstone and shale.

[0211] The drilling fluid safety mud density window determination module is used to determine the lower and upper limits of the window. The lower limit of the window is the formation collapse pressure, and the upper limit is the formation leakage pressure.

[0212] The drilling fluid performance determination module is used to determine drilling fluid performance based on rock mechanics parameters, geostress, and formation component content.

[0213] The module division in this embodiment of the invention is illustrative and represents only one logical functional division. In actual implementation, other division methods may be used. Furthermore, the functional modules in the various embodiments of the invention can be integrated into a single processor, exist as separate physical entities, or be integrated into a single module. The integrated modules described above can be implemented in hardware or as software functional modules.

[0214] In another embodiment of the present invention, a computer device is provided, comprising a processor and a memory. The memory stores a computer program, which includes program instructions. The processor executes the program instructions stored in the computer storage medium. The processor may be a Central Processing Unit (CPU), or other general-purpose processors, digital signal processors (DSPs), application-specific integrated circuits (ASICs), field-programmable gate arrays (FPGAs), or other programmable logic devices, discrete gate or transistor logic devices, discrete hardware components, etc. It is the computing and control core of the terminal, suitable for implementing one or more instructions, specifically suitable for loading and executing one or more instructions in the computer storage medium to achieve a corresponding method flow or corresponding function. The processor described in this embodiment of the present invention can be used in the operation of a method for improving wellbore stability using water-based drilling fluids.

[0215] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention and not to limit it. Although the present invention has been described in detail with reference to the above embodiments, those skilled in the art should understand that modifications or equivalent substitutions can still be made to the specific implementation of the present invention. Any modifications or equivalent substitutions that do not depart from the spirit and scope of the present invention should be covered within the scope of protection of the claims of the present invention.

Claims

1. A method for improving wellbore stability using water-based drilling fluid, characterized in that, Includes the following steps: Utilize conventional well logging curves to finely evaluate the lithological and mineral composition of formations; Obtain rock mechanical parameters under complex lithological backgrounds; The current geostress value is obtained by using the wellbore fracture trajectory inversion method based on rock mechanics parameters; Based on the stratigraphic lithology and mineral composition, the relationship between mineral component content and water-based mud filtrate intrusion was established, and a calculation method for collapse pressure under the mechanical-chemical coupling effect of mudstone and shale was constructed. Determining the safe mud density window for drilling fluid: Clearly define the lower and upper limits of the window. The lower limit of the window is the formation collapse pressure, and the upper limit is the formation leakage pressure. Based on rock mechanics parameters, geostress, and formation component content, the drilling fluid properties are determined; Collapse pressure calculation: Using conventional well logging curves, the mineral composition profile of rocks is precisely evaluated. Based on the extraction of mineral component content, the relationship between mineral component content and water-based mud filtrate intrusion is established, and a method for calculating collapse pressure under the mechanical-chemical coupling effect of shale is constructed. Equation for mud filtrate intrusion in shale formations: In the formula: This is the error compensation function; Initial water content of mudstone and shale, unit: % Saturated water content of mudstone and shale, in % %. The water absorption and diffusion coefficient of mudstone and shale is related to the properties of the mud slurry. (Unit: cm) 2 / h;t: Formation soaking time of drilling mud filtrate after wellbore drilling, unit: h; x: Distance from the wellbore, in cm; W: Intrusion rate of mud and shale mud filtrate, in %; Establish the relationship between mineral component content and mud filtrate intrusion amount; Substitute the relationship between clay content and mud filtrate intrusion amount into the formula for calculating stone mechanical parameters: Quantitative calculation formula for Young's modulus under mechanical-chemical coupling of shale and mudstone: Quantitative formula for calculating Poisson's ratio under the mechanical-chemical coupling effect of shale: Quantitative calculation formula for cohesion under mechanical-chemical coupling of shale and mudstone: Quantitative calculation formula for the internal friction angle of shale under mechanical-chemical coupling: In the above formula: Ea, Eb, Va, Vb, Regional empirical coefficient, unit: dimensionless; Ks: coefficient, unit: dimensionless; Wb: initial water cut increment, unit: % VCL: Clay content, unit: % a, b: Coefficients relating mud filtrate intrusion amount to mud content, unit: dimensionless; Current quantitative calculation of horizontal geostress: Quantitative calculation formula for maximum horizontal principal stress under mechanical-chemical coupling of shale and mudstone: Quantitative calculation formula for minimum horizontal principal stress under mechanical-chemical coupling of shale and mudstone: In the formula: Tz: Vertical stress; Unit: MPa; biot: rock parameter biot coefficient; unit: dimensionless; Pp: formation pore pressure; unit: MPa; x, y: structural strain coefficients along the direction of maximum horizontal principal stress and the direction of minimum principal stress, respectively, in dimensionless units; Quantitative calculation formula for collapse pressure under the mechanical-chemical coupling effect of shale: In the formula: a: Stress nonlinearity correction factor, unit: dimensionless.

2. The method for improving wellbore stability using water-based drilling fluid according to claim 1, characterized in that, The evaluation of stratigraphic lithology and mineral composition specifically includes: Based on the logging cuttings repositioning data, the formation lithology was determined, and the mineral composition was calculated using the volumetric theory model. Calculation of clay content: In the formula: GR is the natural gamma of the logging curve, in units of Ap; GRmin and GRmax are the minimum and maximum values ​​of the natural gamma, respectively, in units of Ap; 1. Clay content index, unit: dimensionless; GCUR is the Hill's index, unit: dimensionless; VCL is clay content, unit: dimensionless. Porosity calculation: In the formula: PIGN stands for porosity, and its unit is dimensionless. The time difference for P-wave measurement is expressed in µs / ft. The time difference for the rock skeleton is expressed in µs / ft. Fluid time difference, unit: µs / ft; Compaction correction factor, unit: dimensionless; Time difference for mudstone skeleton; unit: µs / ft; Modified methods for evaluating mineral groups: Pure salt content: GR < 30 Api, DT > 60 μS / ft, RT > 2000 Ω•m and PIGN = 0; Pure ointment content: GR < 30 Api, DT < 60 μS / ft, RT > 2000 Ω•m and PIGN = 0; Migration content: determined based on the volumetric theory model. In the formula: DT is the measured sonic transit time, in µs / ft; VQ is the volumetric content of migmatite, in dimensionless units; VS is the volumetric content of salt rock, in dimensionless units; VH is the volumetric content of gypsum rock, in dimensionless units; RT is the formation resistivity, in Ω•m.

3. The method for improving wellbore stability with water-based drilling fluid according to claim 1, characterized in that, Obtaining rock mechanical parameters: Rock mechanics parameters related to wellbore stability include rock compressive strength, Poisson's ratio, Young's modulus, and tensile strength. Obtaining these parameters involves two steps: First, obtaining underground rock cores for rock mechanics experiments to acquire static values ​​of the aforementioned parameters. Then, using acoustic, density, and gamma data obtained from well logging, the dynamic values ​​of these parameters are calculated using theoretical formulas. Second, establishing the conversion relationship between dynamic and static values ​​of the rock mechanics parameters involves converting the dynamic values ​​obtained from well logging into static values ​​to obtain the aforementioned parameters. Combined with rock composition analysis, the rock mechanics parameter values ​​under different lithological backgrounds are determined.

4. The method for improving wellbore stability with water-based drilling fluid according to claim 3, characterized in that, Obtaining the geostress value: The vertical stress Sv of the overlying strata was obtained using the density logging curve integration method. The range of the minimum horizontal principal stress Sh in the region was obtained using hydraulic fracturing. The formation pore pressure Pp data was obtained using the equivalent depth method and rock compressive strength data. Drilling fluid density data was obtained from actual drilling data. Wellbore collapse caused by stress release was identified from electrical imaging logging images, and collapse width data was read from the images. Stress polygons were constructed according to the slopes determined by different algorithms, and the compressive strength was marked in the stress polygons according to the matching relationship between formation compressive strength and stress. The stress value of the target well was obtained by using the various parameters obtained by the above methods and the relationships between the following parameters.

5. The method for improving wellbore stability with water-based drilling fluid according to claim 1, characterized in that, Determining the drilling fluid density window requires clarifying the lower and upper limits of the window. The lower limit of the window is the formation collapse pressure, and the upper limit is the formation leakage pressure. The formation collapse pressure considers two factors: one is the formation collapse pressure with mudstone and shale content, which is called Wmin1; the other is the formation collapse pressure when considering the weak surface of the formation, which is called Wmin2 here. Then compare Wmin1 and Wmin2, and the larger of the two is the lower limit of the drilling fluid safe mud density window; The upper limit of the density window is the drilling fluid density at which the weak surface of the formation is opened by the drilling fluid during the drilling process, resulting in leakage. This density is called the critical opening pressure of the weak surface formation, which is referred to as Wmax. Finally, the larger of Wmin1 and Wmin2 and Wmax are used as the basis for designing the drilling fluid safety density window.

6. The method for improving wellbore stability with water-based drilling fluid according to claim 5, characterized in that, Determining Wmax: The stress on the natural crack surface is decomposed into effective normal stress along the normal direction of the crack surface. Effective shear stress parallel to the crack surface ; The calculation method for the critical opening pressure of a natural fracture, i.e., the leakage pressure, is as follows: In the formula: Sv: Vertical stress, unit: MPa; : Coefficient of sliding friction in natural cracks, dimensionless; : Natural fissure dip angle, unit: °; Natural tendency to crack, unit: °; Principal stress orientation, unit: °.

7. The method for improving wellbore stability with water-based drilling fluid according to claim 1, characterized in that, The properties of water-based drilling fluids include rheology, inhibition, plugging properties, and thermal stability. Their determination involves four processes: First, based on the rock mechanics, geostress, and formation component content established in the previous process, the relationship between drilling fluid density, mud activity, and wellbore collapse width is established. While determining the drilling fluid density, the wellbore collapse width is kept no higher than 30 degrees to determine the drilling fluid activity value. Then, according to the conversion relationship between activity and salinity, the activity is converted to salinity to determine the total salinity of the drilling fluid. Second, the content of the drilling fluid's inhibition formulation is determined, with a clay content higher than... When the clay content is 50%, potassium chloride is added to 7%; when the clay content is 50%-20%, potassium chloride is added to 3-5%; when the clay content is less than 20%, potassium chloride is not needed. Thirdly, the solid content is determined by considering drilling flow rate, pump pressure, and tubing structure parameters to determine the requirements for drilling fluid suspension capacity and wellbore cleaning capacity, calculating drilling fluid shear force and viscosity parameters to determine the amount of solid material to be added. Fourthly, based on the changes in formation temperature under different well depths, experiments are conducted to determine the thickening and deposition of drilling fluid at different temperatures, thereby determining the amount of high-temperature resistant material to be added to the drilling fluid.

8. A water-based drilling fluid system for improving wellbore stability, characterized in that, include: The formation lithology and mineral composition acquisition module is used to finely evaluate the formation lithology and mineral composition using conventional well logging curves; The rock mechanics parameter acquisition module is used to acquire rock mechanics parameters under complex lithological backgrounds; The geostress value acquisition module is used to obtain the current geostress value based on rock mechanics parameters using the wellbore fracture trajectory inversion method. The collapse pressure calculation module is used to establish the relationship between mineral component content and water-based mud filtrate intrusion amount based on the lithological and mineral composition of the formation, and to construct the collapse pressure calculation under the mechanical-chemical coupling effect of mudstone and shale. The drilling fluid safety mud density window determination module is used to determine the lower and upper limits of the window. The lower limit of the window is the formation collapse pressure, and the upper limit is the formation leakage pressure. The drilling fluid performance determination module is used to determine drilling fluid performance based on rock mechanics parameters, geostress, and formation component content. Collapse pressure calculation: Using conventional well logging curves, the mineral composition profile of rocks is precisely evaluated. Based on the extraction of mineral component content, the relationship between mineral component content and water-based mud filtrate intrusion is established, and a method for calculating collapse pressure under the mechanical-chemical coupling effect of shale is constructed. Equation for mud filtrate intrusion in shale formations: In the formula: This is the error compensation function; Initial water content of mudstone and shale, unit: % Saturated water content of mudstone and shale, in % %. The water absorption and diffusion coefficient of mudstone and shale is related to the properties of the mud slurry. (Unit: cm) 2 / h;t: Formation soaking time of drilling mud filtrate after wellbore drilling, unit: h; x: Distance from the wellbore, in cm; W: Intrusion rate of mud and shale mud filtrate, in %; Establish the relationship between mineral component content and mud filtrate intrusion amount; Substitute the relationship between clay content and mud filtrate intrusion amount into the rock mechanics parameter calculation formula: Quantitative calculation formula for Young's modulus under mechanical-chemical coupling of shale and mudstone: Quantitative formula for calculating Poisson's ratio under the mechanical-chemical coupling effect of shale: Quantitative calculation formula for cohesion under mechanical-chemical coupling of shale and mudstone: Quantitative calculation formula for the internal friction angle of shale under mechanical-chemical coupling: In the above formula: Ea, Eb, Va, Vb, Regional empirical coefficient, unit: dimensionless; Ks: coefficient, unit: dimensionless; Wb: initial water cut increment, unit: % VCL: Clay content, unit: % a, b: Coefficients relating mud filtrate intrusion amount to mud content, unit: dimensionless; Current quantitative calculation of horizontal geostress: Quantitative calculation formula for maximum horizontal principal stress under mechanical-chemical coupling of shale and mudstone: Quantitative calculation formula for minimum horizontal principal stress under mechanical-chemical coupling of shale and mudstone: In the formula: Tz: Vertical stress; Unit: MPa; biot: rock parameter biot coefficient; unit: dimensionless; Pp: formation pore pressure; unit: MPa; x, y: structural strain coefficients along the direction of maximum horizontal principal stress and the direction of minimum principal stress, respectively, in dimensionless units; Quantitative calculation formula for collapse pressure under the mechanical-chemical coupling effect of shale: In the formula: a: Stress nonlinearity correction factor, unit: dimensionless.

9. A computer device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that, When the processor executes the computer program, it implements the steps of the method for improving wellbore stability using water-based drilling fluid as described in any one of claims 1 to 7.

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