Method for optimizing drilling fluid density in shale formations

Abstract

The application provides a shale formation drilling fluid density optimization design method, including obtaining physical property parameters of shale cores; establishing a borehole wall instability mechanics model with a weak surface structure according to a borehole wall instability mechanism; judging borehole surrounding rock collapse conditions according to a Mohr-Coulomb failure criterion and a weak surface failure criterion, and determining minimum and maximum drilling fluid densities for maintaining shale formation borehole wall stability in combination with an engineering allowable collapse degree; fitting a relationship between a mechanical drilling speed of a shale formation and a static column pressure of a drilling fluid at different depths, and calculating an upper limit value of the drilling fluid density at a critical mechanical drilling speed; and obtaining a design range of a drilling fluid density window of the shale formation considering borehole wall stability and fast drilling according to the minimum drilling fluid density, the maximum drilling fluid density and the upper limit value of the drilling fluid density at the critical mechanical drilling speed. The optimization design method can obtain a lower limit of the drilling fluid density meeting the engineering allowable collapse degree and an upper limit of the drilling fluid density of the optimal mechanical drilling speed.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas drilling technology, and particularly relates to a method for optimizing the design of drilling fluid density in shale formations. Background Technology

[0002] With the development of exploration and drilling technology, vast natural gas resources exist in the deep sea. However, due to the limitations of high temperature and high pressure conditions, drilling and development face difficulties. When drilling into deep plastic shale formations, engineering problems such as mud pockets, wellbore instability, and low mechanical drilling rates arise, severely restricting operational efficiency and bringing high costs and safety risks to deep-sea drilling. From a mechanical perspective, wellbore instability in shale formations is due to the low strength of the shale, which cannot balance the stress near the wellbore, leading to stress concentration and imbalance near the wellbore. This causes shear or tensile failure of the shale, resulting in wellbore instability. Currently, drilling fluid density design primarily focuses on wellbore stability and does not consider the impact of drilling fluid density on mechanical drilling rates, indicating a deficiency in the design of drilling fluid density windows. Summary of the Invention

[0003] The main objective of this invention is to propose a method for optimizing the design of drilling fluid density in shale formations, aiming to solve the technical problem that current drilling fluid density design mainly focuses on wellbore stability and does not consider the impact of drilling fluid density on mechanical drilling rate.

[0004] To achieve the above objectives, the present invention provides a method for optimizing drilling fluid density in shale formations, comprising the following steps:

[0005] Obtain the physical properties of mudstone and shale cores;

[0006] A wellbore instability mechanical model with weak surface structure was established based on the wellbore instability mechanism.

[0007] The collapse of the surrounding rock was judged based on the Mohr-Coulomb failure criterion and the weak surface failure criterion, and the minimum and maximum drilling fluid densities for maintaining the wellbore stability of the shale formation were determined in combination with the allowable degree of collapse in the project.

[0008] The relationship between mechanical drilling rate and hydrostatic pressure of drilling fluid in shale formations at different depths of drilled wells was fitted, and the upper limit of drilling fluid density under the critical mechanical drilling rate was calculated.

[0009] The design range of the drilling fluid density window for shale formations, considering wellbore stability and rapid drilling, is obtained based on the minimum drilling fluid density, the maximum drilling fluid density, and the upper limit of drilling fluid density at the critical mechanical drilling rate.

[0010] In an embodiment of the present invention, the step of obtaining the physical property parameters of the shale core is further included before the following step:

[0011] Collect on-site data of the oilfield blocks;

[0012] Determine the mudstone and shale formation region of the exploration well based on gamma logging;

[0013] Core samples were taken from the wellbore in the shale formation to obtain shale cores.

[0014] In an embodiment of the present invention, the shale formation includes a rock mass and a weak surface structure. The step of determining the collapse of the surrounding rock according to the Mohr-Coulomb failure criterion and the weak surface failure criterion, and determining the minimum and maximum drilling fluid densities for maintaining wellbore stability in the shale formation in combination with the engineering allowable collapse degree, includes:

[0015] To obtain the geostress distribution of mudstone and shale formations;

[0016] Stress distribution values ​​of mudstone and shale formations and stress distribution values ​​of weak surface structures at specific angles were obtained by coordinate transformation.

[0017] The stress distribution values ​​of the transformed shale formation and the stress distribution values ​​of the weak surface structure at a specific angle were respectively substituted into the Mohr-Coulomb failure criterion and the weak surface failure criterion to obtain the collapse distribution around the wellbore.

[0018] Within the permissible collapse limits of the project, obtain the minimum and maximum drilling fluid densities for maintaining wellbore stability.

[0019] In an embodiment of the present invention, the step of obtaining stress distribution values ​​of mudstone and shale formations through coordinate transformation includes:

[0020] Obtain the stress distribution values ​​of shale formations in the principal stress coordinate system;

[0021] Transform the stress distribution values ​​of the mudstone and shale formation from the principal stress coordinate system to the geodetic coordinate system;

[0022] The stress distribution values ​​in the geodetic coordinate system are converted to the wellbore coordinate system. The stress distribution values ​​in the wellbore coordinate system are the current stress distribution values ​​of the mudstone and shale formation.

[0023] In an embodiment of the present invention, the step of substituting the converted stress distribution values ​​of the shale formation and the stress distribution values ​​of the weak surface structure at a specific angle into the Mohr-Coulomb failure criterion and the weak surface failure criterion, respectively, to obtain the collapse distribution around the wellbore includes:

[0024] Determine whether the shale formation has failed under the stress distribution value according to the Mohr-Coulomb failure criterion.

[0025] Determine whether a weak-plane structure fails under the stress distribution value of a weak-plane structure based on the weak-plane failure criterion.

[0026] In an embodiment of the present invention, the step of determining whether the weak surface structure fails under the stress distribution value of the weak surface structure according to the weak surface failure criterion includes:

[0027] Establish a coordinate system for the weak surface;

[0028] Transform the stress distribution values ​​of the shale formation from the wellbore coordinate system to the geodetic coordinate system;

[0029] The stress of the weak surface in the geodetic coordinate system is transformed to the weak surface coordinate system to obtain the stress distribution value of the weak surface structure in the weak surface coordinate system. The stress distribution value of the weak surface structure is then substituted into the weak surface failure criterion.

[0030] If the stress distribution value of the weak surface structure meets the weak surface failure criterion, it indicates that the weak surface structure has failed under the current stress distribution value of the mudstone and shale formation.

[0031] In an embodiment of the present invention, the step of determining whether the shale formation has failed under the stress distribution value of the shale formation according to the Mohr-Coulomb failure criterion includes:

[0032] If the stress distribution value of the shale formation satisfies the Mohr-Coulomb failure criterion, it indicates that the shale formation has failed under the current stress distribution value.

[0033] In an embodiment of the present invention, the step of fitting the relationship between the mechanical drilling rate and the hydrostatic pressure of the drilling fluid at different depths in the drilled well in the shale formation, and calculating the upper limit of the drilling fluid density at the critical mechanical drilling rate, includes:

[0034] Obtain the hydrostatic column pressure at different depths and record the scatter plot of the relationship between mechanical drilling rate and hydrostatic column pressure in the same coordinate system;

[0035] Multiple scattered points are linearly fitted in the same coordinate system to obtain the upper limit of drilling fluid density under the critical mechanical drilling rate.

[0036] In an embodiment of the present invention, the step of obtaining the design range of the drilling fluid density window for shale formations, considering wellbore stability and rapid drilling, based on the minimum drilling fluid density, the maximum drilling fluid density, and the upper limit of the drilling fluid density at the critical mechanical drilling rate, includes:

[0037] The minimum of the two values—the maximum drilling fluid density that satisfies wellbore stability and the upper limit of the drilling fluid density that satisfies the fastest drilling speed—is taken as the upper limit of the drilling fluid density window.

[0038] The minimum drilling fluid density that satisfies wellbore stability is taken as the lower limit of the drilling fluid density window.

[0039] In an embodiment of the present invention, the step of obtaining the physical property parameters of the shale core and the step of establishing a wellbore instability mechanical model based on the wellbore instability mechanism further include:

[0040] A triaxial compression test was conducted on the shale core, and the physical properties of the shale core were obtained.

[0041] Through the above technical solution, the drilling fluid density optimization design method for shale formations provided by the embodiments of the present invention has the following beneficial effects:

[0042] In designing the drilling fluid density window, the following steps are taken: First, the physical properties of the shale core are obtained. A wellbore instability mechanical model with weak surface structures is established based on the wellbore instability mechanism. The collapse of the surrounding rock is assessed using the Mohr-Coulomb failure criterion and the weak surface failure criterion. The minimum and maximum drilling fluid densities for maintaining wellbore stability in shale formations are determined by combining the allowable collapse degree with the engineering considerations. Second, the relationship between the mechanical drilling rate and the hydrostatic pressure of the drilling fluid in shale formations at different depths in drilled wells is fitted, and the upper limit of the drilling fluid density under the critical mechanical drilling rate is calculated. Finally, the design range of the drilling fluid density window for shale formations considering wellbore stability and rapid drilling is obtained based on the minimum, maximum, and upper limit values ​​of the drilling fluid density under the critical mechanical drilling rate. This application considers both wellbore stability when encountering plastic shale and the mechanical drilling rate in the drilling fluid density optimization design, thus overcoming the shortcomings of current drilling fluid density window designs.

[0043] Other features and advantages of the present invention will be described in detail in the following detailed description section. Attached Figure Description

[0044] The accompanying drawings are provided to illustrate the invention and form part of the specification. They are used together with the following detailed description to explain the invention, but do not constitute a limitation thereof. In the drawings:

[0045] Figure 1 This is a flowchart illustrating a drilling fluid density optimization design method for shale formations according to an embodiment of the present invention.

[0046] Figure 2 This is a logging and well logging data map of an oilfield block according to an embodiment of the present invention;

[0047] Figure 3 These are wellbore collapse cloud maps under different drilling fluid density conditions according to the first embodiment of the present invention;

[0048] Figure 4 This is a graph showing the relationship between wellbore enlargement rate and drilling fluid density according to the first embodiment of the present invention;

[0049] Figure 5 This is a schematic diagram illustrating the relationship between mechanical drilling speed and hydrostatic column pressure according to the first embodiment of the present invention;

[0050] Figure 6 This is a wellbore collapse cloud map under different drilling fluid density conditions according to the second embodiment of the present invention;

[0051] Figure 7 This is a graph showing the relationship between wellbore enlargement rate and drilling fluid density according to the second embodiment of the present invention;

[0052] Figure 8 This is a schematic diagram showing the relationship between mechanical drilling speed and hydrostatic column pressure according to the second embodiment of the present invention. Detailed Implementation

[0053] The specific embodiments of the present invention will be described in detail below with reference to the accompanying drawings. It should be understood that the specific embodiments described herein are for illustration and explanation only and are not intended to limit the present invention.

[0054] The following describes the drilling fluid density optimization design method for shale formations according to the present invention with reference to the accompanying drawings.

[0055] like Figure 1 As shown in the embodiments of the present invention, a method for optimizing the density of drilling fluid in shale formations is provided, comprising the following steps:

[0056] S10: Obtain the physical properties of shale cores;

[0057] S20: Establish a mechanical model of wellbore instability with weak surface structures based on the wellbore instability mechanism;

[0058] S30: Determine the collapse of the surrounding rock based on the Mohr-Coulomb failure criterion and the weak surface failure criterion, and determine the minimum and maximum drilling fluid densities to maintain the stability of the wellbore in the shale formation by combining the allowable degree of collapse in the project.

[0059] S40: Fit the relationship between mechanical drilling rate and hydrostatic pressure of drilling fluid in shale formations at different depths of drilled wells, and calculate the upper limit of drilling fluid density under the critical mechanical drilling rate.

[0060] S50: The design range of the drilling fluid density window for shale formations, taking into account wellbore stability and rapid drilling, is obtained based on the minimum drilling fluid density, maximum drilling fluid density, and the upper limit of drilling fluid density at the critical mechanical drilling rate.

[0061] The drilling fluid density optimization design method for shale formations in this application considers both the wellbore stability when encountering plastic shale and the influence of mechanical drilling rate. It can derive the lower limit of drilling fluid density that meets the allowable degree of engineering collapse and the upper limit of drilling fluid density for the optimal mechanical drilling rate, thus making up for the deficiencies in the existing technology.

[0062] In embodiments of the present invention, the step of obtaining the physical property parameters of shale cores is further included before the following steps:

[0063] Collect on-site data of the oilfield blocks;

[0064] Determine the mudstone and shale formation region of the exploration well based on gamma logging;

[0065] Core samples were taken from the wellbore in the shale formation to obtain shale cores.

[0066] This embodiment collects field data from a specific block in an oilfield, analyzes well logging and drilling data, and identifies the X group of mudstone and shale formations based on gamma logging. Mudstone formations with high gamma values ​​have low mechanical drilling rates, while sandstone formations have high mechanical drilling rates. For example... Figure 2 As shown, the second column of lithology dots represents sandstone, and the horizontal lines represent mudstone. GR represents the gamma ray logging value. Mudstone and shale have high gamma ray values ​​and low mechanical drilling rates. Using gamma ray values ​​to determine the mudstone and shale formations in this oilfield provides a basis for subsequent performance analysis of the mudstone and shale.

[0067] In an embodiment of the present invention, the step of determining the collapse of the surrounding rock based on the Mohr-Coulomb failure criterion and the weak-surface failure criterion, and determining the minimum and maximum drilling fluid densities for maintaining wellbore stability in shale formations in conjunction with the engineering allowable collapse degree, includes:

[0068] To obtain the geostress distribution of mudstone and shale formations;

[0069] Stress distribution values ​​of mudstone and shale formations and stress distribution values ​​of weak surface structures at specific angles were obtained by coordinate transformation.

[0070] The stress distribution values ​​of the transformed shale formation and the stress distribution values ​​of the weak surface structure at a specific angle were respectively substituted into the Mohr-Coulomb failure criterion and the weak surface failure criterion to obtain the collapse distribution around the wellbore.

[0071] Within the permissible collapse limits of the project, obtain the minimum and maximum drilling fluid densities for maintaining wellbore stability.

[0072] This embodiment determines the collapse of the surrounding rock based on the Mohr-Coulomb failure criterion and the weak surface failure criterion, and combines the allowable wellbore collapse degree (wellbore enlargement rate) to determine the minimum and maximum drilling fluid density ranges for maintaining wellbore stability in shale formations, thereby improving the accuracy of drilling fluid density range calculation.

[0073] In an embodiment of the present invention, the step of obtaining stress distribution values ​​of mudstone and shale formations through coordinate transformation includes:

[0074] Obtain the stress distribution values ​​of shale formations in the principal stress coordinate system;

[0075] Transform the stress distribution values ​​of the mudstone and shale formation from the principal stress coordinate system to the geodetic coordinate system;

[0076] The stress distribution values ​​in the geodetic coordinate system are converted to the wellbore coordinate system. The stress distribution values ​​in the wellbore coordinate system are the current stress distribution values ​​of the mudstone and shale formation.

[0077] In an embodiment of the present invention, the step of substituting the converted stress distribution values ​​of the shale formation and the stress distribution values ​​of the weak surface structure at a specific angle into the Mohr-Coulomb failure criterion and the weak surface failure criterion, respectively, to obtain the collapse distribution around the wellbore includes:

[0078] Determine whether the shale formation has failed under the stress distribution value according to the Mohr-Coulomb failure criterion.

[0079] Determine whether a weak-plane structure fails under the stress distribution value of a weak-plane structure based on the weak-plane failure criterion.

[0080] The Mohr-Coulomb violation criterion is as follows:

[0081] C0 and u0 represent the maximum and minimum principal stresses of the wellbore rock, respectively, and C0 and u0 represent the cohesion and internal friction coefficient of the rock body, respectively.

[0082] The weak surface failure criterion is as follows:

[0083] For the shear stress on the weak surface structure, σ bp For the normal stress on the weak surface structure, C bp ,u bp These represent the cohesion and internal friction coefficient of the weak surface structure, respectively.

[0084] In an embodiment of the present invention, the step of determining whether the shale formation has failed under the stress distribution value according to the Mohr-Coulomb failure criterion includes:

[0085] If the stress distribution value of the shale formation satisfies the Mohr-Coulomb failure criterion, it indicates that the shale formation has failed under the current stress distribution value.

[0086] This embodiment considers a mechanical wellbore stability model based on weak surfaces. First, the in-situ stress values ​​of the shale formation in the principal stress coordinate system are transformed to the geodetic coordinate system:

[0087]

[0088]

[0089]

[0090] Where, σ P The geostress tensor in the principal geostress coordinate system; σ e It is the geostress tensor in the geodetic coordinate system; α s It is the azimuth angle of the maximum principal stress; β s It is the angle between the stress of the overlying rock strata and the vertical positive axis.

[0091] Then, the geostress is transformed from the geodetic coordinate system to the wellbore coordinate system. The specific transformation formula is as follows:

[0092]

[0093]

[0094] In the wellbore coordinate system, α b It is the well inclination azimuth; β b It is the well inclination angle; σ b It is the geostress tensor; θ is the wellbore angle.

[0095] In an embodiment of the present invention, the step of determining whether the weak surface structure fails under the stress distribution value of the weak surface structure according to the weak surface failure criterion includes:

[0096] Establish a coordinate system for the weak surface;

[0097] Transform the stress distribution values ​​of the shale formation from the wellbore coordinate system to the geodetic coordinate system;

[0098] The stress of the weak surface in the geodetic coordinate system is transformed to the weak surface coordinate system to obtain the stress distribution value of the weak surface structure in the weak surface coordinate system. The stress distribution value of the weak surface structure is then substituted into the weak surface failure criterion.

[0099] If the stress distribution value of the weak surface structure meets the weak surface failure criterion, it indicates that the weak surface structure has failed under the current stress distribution value of the mudstone and shale formation.

[0100] Specifically, considering the failure of the weak surface, it is necessary to establish a weak surface coordinate system. For the calculation of the geostress distribution, this application first transforms it from the wellbore coordinate system to the geodetic coordinate system, and then transforms it to the weak surface coordinate system. The specific transformation method is as follows:

[0101]

[0102]

[0103]

[0104] Where, β bp These are the weak surface inclination angles, It represents the tendency of the weak side; p is the pore pressure; α is the Biot coefficient, σ bp It is the stress tensor in the weak surface coordinate system.

[0105] Furthermore, the wellbore instability mechanical model with weak surface structures also includes the following equations:

[0106] Considering the differences in mechanical parameters perpendicular to and parallel to the strata, the strata rocks are treated as transversely isotropic materials, and the constitutive equation is:

[0107]

[0108] Due to deposition, each layer has approximately the same elastic properties in the plane, but different properties in the vertical direction. Assuming the bedding is horizontal and the wellbore is perpendicular to the bedding plane, the coefficients of the stiffness matrix are:

[0109]

[0110]

[0111]

[0112]

[0113] Where E and E′ are the elastic moduli parallel and perpendicular to the bedding planes, respectively, in GPa. G and G′ are the shear moduli parallel and perpendicular to the bedding planes, respectively, in GPa. υ and υ′ are the Poisson's ratios parallel and perpendicular to the bedding planes, respectively.

[0114] The Biot coefficient for a transversely isotropic medium is:

[0115]

[0116]

[0117] Among them, K sIt is the bulk modulus of the rocks in the strata.

[0118] The stress balance equation is:

[0119] σ ji,j =0

[0120] The geometric equation is:

[0121]

[0122] In an embodiment of the present invention, the step of fitting the relationship between the mechanical drilling rate and the hydrostatic pressure of the drilling fluid at different depths in the drilled well in the shale formation, and calculating the upper limit of the drilling fluid density at the critical mechanical drilling rate, includes:

[0123] Obtain the hydrostatic pressure at different depths and record the scatter plot of the relationship between mechanical drilling rate and hydrostatic pressure in the same coordinate system.

[0124] Multiple scattered points are linearly fitted in the same coordinate system to obtain the upper limit of drilling fluid density under the critical mechanical drilling rate.

[0125] Furthermore, the critical drilling rate is defined as the drilling rate that satisfies both safety and economic efficiency. The relationship between the mechanical drilling rate and the hydrostatic pressure of the drilling fluid in shale formations at different depths can be fitted by the following formula:

[0126] P = 0.00981ρH

[0127] Where P is the hydrostatic pressure of the drilling fluid, ρ is the upper limit of the drilling fluid density at the critical drilling rate, and H is the well depth.

[0128] In an embodiment of the present invention, the step of obtaining the design range of the drilling fluid density window for shale formations, considering wellbore stability and rapid drilling, based on the minimum drilling fluid density, the maximum drilling fluid density, and the upper limit of the drilling fluid density at the critical mechanical drilling rate, includes:

[0129] The minimum value between the maximum drilling fluid density that satisfies wellbore stability and the upper limit value of drilling fluid density that satisfies rapid drilling is the upper limit value of the drilling fluid density window.

[0130] The minimum drilling fluid density that satisfies wellbore stability is taken as the lower limit of the drilling fluid density window.

[0131] In embodiments of the present invention, the step between obtaining the physical property parameters of shale cores and establishing a wellbore instability mechanical model based on the wellbore instability mechanism further includes:

[0132] Triaxial compression tests were conducted on shale cores to obtain their physical properties.

[0133] In the triaxial compression test of the rock, a triaxial compression test device commonly used in existing technology is adopted. The elastic mechanical parameters, rock strength, weak surface strength, and in-situ stress of the mudstone and shale core are tested through the triaxial compression test of the rock. On the one hand, it can study the properties of the mudstone and shale in the formation, and on the other hand, it can provide parameter basis for subsequent calculations.

[0134] To further understand the drilling fluid density window design method of this application, the following detailed description is provided in conjunction with two practical embodiments:

[0135] Example 1:

[0136] Taking an exploration well in Block M of an offshore oilfield as an example, the well encountered a low-pressure mudstone and shale formation. Formation information, lithological characteristics, drilling fluid density, logging data, and downhole core samples were obtained through logging, drilling while drilling, and core sampling. The logging data included well diameter and gamma ray readings, and the drilling complexity was analyzed. High-gamma ray mudstone formations have low mechanical drilling rates, while sandstone formations have high mechanical drilling rates, such as… Figure 2 As shown.

[0137] By lowering a core sampler to a predetermined depth using a cable, shale cores are retrieved from the open-hole wellbore. Triaxial compression tests are then conducted to assess the rock's elastic mechanical parameters, bulk strength, weak-surface strength, and formation stress. The rock's elastic mechanical parameters include elastic modulus and Poisson's ratio; bulk strength includes bulk cohesion and internal friction angle; weak-surface strength includes weak-surface cohesion and friction angle; and formation stress includes overlying strata pressure, maximum horizontal principal stress, and minimum horizontal principal stress. The parameters of the model in this embodiment are shown in Table 1.

[0138] Table 1. Wellbore stability model parameters for shale formations under normal pressure

[0139]

[0140]

[0141] In general, oilfield operations consider a wellbore enlargement rate of less than 15% to meet wellbore stability requirements. Therefore, a wellbore instability mechanics model is used to solve for the stress around the wellbore under different drilling fluid densities. Based on the Mohr-Coulomb failure criterion and the failure criterion of weak surfaces in the rock matrix, the wellbore collapse situation around the wellbore is determined, and the drilling fluid density window that satisfies a 15% wellbore enlargement rate is analyzed. Here, the wellbore enlargement rate is the ratio of the change in wellbore diameter to the wellbore diameter itself.

[0142] The basic equations of the wellbore instability mechanical model include: constitutive equations, equilibrium equations, geometric equations, and deformation compatibility equations, where fluid stress and solid deformation are coupled. It also includes criteria for judging the failure of the rock mass and the failure of weak surfaces. In this embodiment, the cohesive strength of the weak surface is 8 MPa. The wellbore collapse contour maps under different drilling fluid density conditions are shown below. Figure 3 As shown in the figure, the gray area within the curve range represents the collapse range, and the relationship between wellbore enlargement rate and drilling fluid density is shown in the figure. Figure 4 As shown. The drilling fluid density window ρ for wellbore stability under a 15% wellbore enlargement rate within the engineering allowable collapse range. 井壁稳定min It is 1.46 g / cm 3 ρ 井壁稳定max It is 1.54 g / cm 3 .

[0143] Based on logging data, the drilling fluid density in the shale formation was converted into hydrostatic pressure, and the relationship between the rate of penetration (ROP) and hydrostatic pressure was derived. Figure 5 As shown. Considering the safety and economic benefits of the block, the critical drilling rate is 10 m / h. The relationship between ROP and hydrostatic pressure is fitted: ROP = -0.2324 * P + 24.536. The calculated hydrostatic pressure is 62.66 MPa. Above this pressure, the mechanical drilling rate in this shale formation is significantly reduced. Based on the formula P = 0.00981ρH, the drilling fluid density at this depth is calculated, which is the upper limit of the drilling fluid density ρ at which the mechanical drilling rate in this formation significantly decreases. 钻速max It is 1.57 g / cm³ 3 .

[0144] Based on the aforementioned drilling fluid density design principles, the drilling fluid density design window for achieving wellbore stability and rapid drilling into the shale formation under normal pressure in this oilfield is 1.46–1.54 g / cm³. 3 .

[0145] Example 2: This example describes another exploratory well in Block M, where the formation is an abnormally high-pressure section of mudstone and shale. The process of predicting the drilling fluid density window is the same as in Example 1, using the same method and principle. The differences lie in parameters such as well depth and formation pressure. Specific model values ​​are shown in Table 2.

[0146] Table 2 Wellbore stability model parameters for shale formations under abnormal high pressure.

[0147]

[0148] In Example 2, the cohesive strength of the weak surface is 8 MPa. The wellbore collapse contour maps under different drilling fluid density conditions are as follows: Figure 6 As shown in the figure, the relationship between wellbore enlargement rate and drilling fluid density is as follows: Figure 7As shown. The drilling fluid density window ρ for wellbore stability under a 15% wellbore enlargement rate within the engineering allowable collapse range. 井壁稳定min It is 1.77 g / cm³ 3 ρ 井壁稳定max It is 1.88 g / cm 3 .

[0149] like Figure 8 As shown, the relationship between the drilling rate of power (ROP) and the hydrostatic pressure in this abnormally high-pressure zone is plotted. Figure 8 As can be seen, considering the safety and economic benefits of the block, the critical drilling rate is 10 m / h. By fitting the relationship between ROP and hydrostatic column pressure, ROP = -0.7515*P + 63.94, the calculated hydrostatic column pressure is 71.78 MPa. Beyond this pressure, the mechanical drilling rate decreases significantly. Then, based on the fitted formula P = 0.00981ρH, the drilling fluid density at this depth is calculated, which is the upper limit ρ of the drilling fluid density at which the mechanical drilling rate significantly decreases in this formation. 钻速max It is 1.82 g / cm 3 .

[0150] Based on the drilling fluid density design principles, the drilling fluid density design window for achieving wellbore stability and rapid drilling into the shale formation under abnormally high pressure in this oilfield block is ultimately set at 1.77–1.82 g / cm³. 3 .

[0151] As can be seen from the above two embodiments, the drilling fluid density optimization design method of this application can overcome the shortcomings of the prior art that does not consider the influence of density on mechanical drilling rate. By simultaneously considering the influence of wellbore stability and mechanical drilling rate, the accuracy of the design range of drilling fluid density in shale formations is improved.

[0152] In the description of this invention, it should be understood that the terms "first" and "second" are used for descriptive purposes only and should not be construed as indicating or implying relative importance or implicitly specifying the number of indicated technical features. Thus, a feature defined as "first" or "second" may explicitly or implicitly include at least one of that feature. In the description of this invention, "a plurality of" means at least two, such as two, three, etc., unless otherwise explicitly specified.

[0153] In this invention, unless otherwise explicitly specified and limited, the terms "installation," "connection," "linking," and "fixing," etc., should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral part; they can refer to a mechanical connection, an electrical connection, or a connection that allows communication between them; they can refer to a direct connection or an indirect connection through an intermediate medium; they can refer to the internal communication of two components or the interaction between two components, unless otherwise explicitly limited. Those skilled in the art can understand the specific meaning of the above terms in this invention according to the specific circumstances.

[0154] In the description of this specification, the references to terms such as "one embodiment," "some embodiments," "example," "specific example," or "some examples," etc., indicate that a specific feature, structure, material, or characteristic described in connection with that embodiment or example is included in at least one embodiment or example of the present invention. In this specification, the illustrative expressions of the above terms do not necessarily refer to the same embodiment or example. Furthermore, the specific features, structures, materials, or characteristics described may be combined in any suitable manner in one or more embodiments or examples. Moreover, without contradiction, those skilled in the art can combine and integrate the different embodiments or examples described in this specification, as well as the features of different embodiments or examples.

[0155] Although embodiments of the present invention have been shown and described above, it is understood that the above embodiments are exemplary and should not be construed as limiting the present invention. Those skilled in the art can make changes, modifications, substitutions and variations to the above embodiments within the scope of the present invention.

Claims

1. A method for optimizing the density design of drilling fluid in shale formations, characterized in that, Including the following steps: Obtain the physical properties of mudstone and shale cores; A wellbore instability mechanical model with weak surface structure was established based on the wellbore instability mechanism. The collapse of the surrounding rock was judged based on the Mohr-Coulomb failure criterion and the weak surface failure criterion, and the minimum and maximum drilling fluid densities for maintaining the wellbore stability of the shale formation were determined in combination with the allowable degree of collapse in the project. The relationship between mechanical drilling rate and hydrostatic pressure of drilling fluid in shale formations at different depths of drilled wells was fitted, and the upper limit of drilling fluid density under the critical mechanical drilling rate was calculated. The design range of the drilling fluid density window for shale formations, considering wellbore stability and rapid drilling, is obtained based on the minimum drilling fluid density, the maximum drilling fluid density, and the upper limit of drilling fluid density at the critical mechanical drilling rate. The steps of fitting the relationship between mechanical drilling rate and hydrostatic pressure of drilling fluid in shale formations at different depths of drilled wells, and calculating the upper limit of drilling fluid density at the critical mechanical drilling rate, include: Obtain the hydrostatic column pressure at different depths and record the scatter plot of the relationship between mechanical drilling rate and hydrostatic column pressure in the same coordinate system; Multiple scattered points are linearly fitted in the same coordinate system to obtain the upper limit of drilling fluid density under the critical mechanical drilling rate. The relationship between mechanical drilling rate and hydrostatic pressure of drilling fluid in shale formations at different depths can be fitted using the following formula: P=0.00981 ρ H Where P is the hydrostatic pressure of the drilling fluid. ρ H represents the upper limit of drilling fluid density at the critical drilling rate, where H is the well depth. The steps for obtaining the design range of the drilling fluid density window for shale formations, considering wellbore stability and rapid drilling, based on the minimum drilling fluid density, the maximum drilling fluid density, and the upper limit of drilling fluid density at the critical mechanical drilling rate, include: The minimum value between the maximum drilling fluid density that satisfies wellbore stability and the upper limit of drilling fluid density that satisfies the fastest drilling speed is taken as the upper limit of the drilling fluid density window. The minimum drilling fluid density that satisfies wellbore stability is taken as the lower limit of the drilling fluid density window.

2. The drilling fluid density optimization design method for shale formations according to claim 1, characterized in that, The step prior to obtaining the physical property parameters of the shale core includes the following step: Collect exploration well data for oilfield blocks; Determine the mudstone and shale formation region of the exploration well based on gamma logging; Core samples were taken from the wellbore in the shale formation to obtain shale cores.

3. The drilling fluid density optimization design method for shale formations according to claim 1, characterized in that, The steps for determining the collapse of the surrounding rock based on the Mohr-Coulomb failure criterion and the weak-surface failure criterion, and for determining the minimum and maximum drilling fluid densities for maintaining wellbore stability in shale formations in conjunction with the allowable degree of collapse in engineering, include: To obtain the geostress distribution of mudstone and shale formations; Stress distribution values ​​of mudstone and shale formations and stress distribution values ​​of weak surface structures at specific angles were obtained by coordinate transformation. The stress distribution values ​​of the transformed shale formation and the stress distribution values ​​of the weak surface structure at a specific angle were respectively substituted into the Mohr-Coulomb failure criterion and the weak surface failure criterion to obtain the collapse distribution around the wellbore. Within the permissible collapse limits of the project, obtain the minimum and maximum drilling fluid densities for maintaining wellbore stability.

4. The drilling fluid density optimization design method for shale formations according to claim 3, characterized in that, The steps for obtaining stress distribution values ​​of shale formations through coordinate transformation include: Obtain the stress distribution values ​​of the mudstone and shale formation in the principal stress coordinate system; Transform the stress distribution values ​​of shale formations from the principal stress coordinate system to the geodetic coordinate system; The stress distribution values ​​in the geodetic coordinate system are converted to the wellbore coordinate system. The stress distribution values ​​in the wellbore coordinate system are the current stress distribution values ​​of the mudstone and shale formation.

5. The drilling fluid density optimization design method for shale formations according to claim 3, characterized in that, The step of substituting the converted stress distribution values ​​of the shale formation and the stress distribution values ​​of the weak surface structure at a specific angle into the Mohr-Coulomb failure criterion and the weak surface failure criterion, respectively, to obtain the collapse distribution around the wellbore includes: Determine whether the shale formation has failed under the stress distribution value according to the Mohr-Coulomb failure criterion. Determine whether a weak-plane structure fails under the stress distribution value of a weak-plane structure based on the weak-plane failure criterion.

6. The drilling fluid density optimization design method for shale formations according to claim 5, characterized in that, The steps for determining whether a weak surface structure fails under the stress distribution value according to the weak surface failure criterion include: Establish a coordinate system for the weak surface; Transform the stress distribution values ​​of the shale formation from the wellbore coordinate system to the geodetic coordinate system; The stress of the weak surface in the geodetic coordinate system is transformed to the weak surface coordinate system to obtain the stress distribution value of the weak surface structure in the weak surface coordinate system. The stress distribution value of the weak surface structure is then substituted into the weak surface failure criterion. If the stress distribution value of the weak surface structure meets the weak surface failure criterion, it indicates that the weak surface structure has failed under the current stress distribution value of the mudstone and shale formation.

7. The drilling fluid density optimization design method for shale formations according to claim 5, characterized in that, The steps for determining the failure of shale formations under stress distribution values ​​according to the Mohr-Coulomb failure criterion include: If the stress distribution value of the shale formation satisfies the Mohr-Coulomb failure criterion, it indicates that the shale formation has failed under the current stress distribution value.

8. The drilling fluid density optimization design method for shale formations according to any one of claims 1 to 7, characterized in that, Between the step of obtaining the physical property parameters of the shale core and the step of establishing the wellbore instability mechanical model based on the wellbore instability mechanism, the following is also included: A triaxial compression test was conducted on the shale core, and the physical properties of the shale core were obtained.

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