A method for calculating a fracture formation drilling fluid leakage pressure differential

Abstract

The application relates to a kind of fracture formation drilling fluid leakage pressure difference calculation methods, it includes: based on drilling fluid rheological experiment data, identify the rheological behavior of fracture formation drilling fluid, and obtain the rheological parameter of corresponding rheological behavior, select optimal rheological mode;Fracture parameters of target interval are obtained by using downhole imaging logging data or core laboratory test, the fracture parameters include fracture width;Leakage pressure difference calculation model of drilling fluid radial flow in formation fracture under different rheological modes is constructed;Based on real-time drilling engineering parameters, the leakage pressure difference under given leakage amount and leakage speed is calculated.The application constructs the leakage pressure difference calculation model considering the rheological behavior of non-newtonian fluid, realizes the accurate characterization of drilling fluid leakage dynamics process, solves the problem that non-newtonian characteristics of drilling fluid is not considered in traditional model, and significantly improves the leakage pressure difference prediction precision.

Description

Technical Field

[0001] This invention relates to the field of oil and gas drilling engineering technology, specifically to a method for calculating drilling fluid leakage pressure differential in fractured formations. Background Technology

[0002] Fractured formations are widely developed in oil and gas reservoirs such as carbonate rocks and shale, and their complex fracture networks significantly increase the risk of drilling fluid loss. Drilling fluid loss not only increases operating costs but also induces secondary disasters such as reservoir pore throat blockage and wellbore instability, severely restricting the efficiency of oil and gas resource development. Traditional loss control methods are mostly based on empirical formulas and static models. However, the high heterogeneity of fractured formations, the multiphase nature of fluid seepage mechanisms, and the significant influence of the rheological properties of non-Newtonian drilling fluids (such as polymer mud and oil-based mud) on loss dynamics make it difficult for traditional methods to accurately predict loss pressure differentials.

[0003] Most existing leakage models for fractured formations are based on the Newtonian fluid assumption of Darcy's law, using equivalent permeability to characterize fracture conductivity. However, they fail to adequately consider the influence of the rheological properties of non-Newtonian drilling fluids (such as Bingham fluids and power-law fluids) on leakage pressure differentials. Some studies have proposed formulas for calculating radial flow leakage that do not incorporate non-Newtonian fluid characteristic parameters; others have derived power-law fluid radial flow pressure drop formulas that fail to establish a quantitative correlation between rheological parameters (such as flow index) and fracture geometric parameters and leakage dynamics. These theoretical deficiencies highlight the urgent need to develop high-precision leakage pressure differential models that can dynamically couple rheological properties. Summary of the Invention

[0004] The purpose of this invention is to provide a method for calculating the leakage pressure difference of drilling fluid in fractured formations. This method is used to solve the problem that traditional models do not consider the characteristics of non-Newtonian fluids, making it difficult to achieve high-precision prediction of leakage pressure difference.

[0005] The technical solution adopted by this invention to solve its technical problem is as follows: This method for calculating the leakage pressure difference of drilling fluid in fractured formations includes the following steps;

[0006] Step 1: Based on drilling fluid rheological experimental data, identify the rheological behavior of drilling fluid in fractured formations. The rheological modes include Newtonian fluid, Bingham fluid, and power-law fluid, and obtain the rheological parameters of the corresponding rheological behavior, namely yield stress, plastic viscosity, consistency coefficient, and flow index. Select the optimal rheological mode.

[0007] Step 2: Obtain fracture parameters of the target formation using downhole imaging logging data or core laboratory tests. The fracture parameters include fracture width.

[0008] Step 3: Construct a calculation model for leakage pressure difference of drilling fluids with different rheological modes in the radial flow of formation fractures;

[0009] Step 4: Based on real-time drilling engineering parameters, calculate the leakage pressure difference under a given leakage rate and leakage velocity.

[0010] Step two in the above scheme is as follows: using downhole imaging logging data or core analysis data, obtain the fracture parameters of the target section. For the dominant leakage channel, it is equivalent to a parallel plate geometric model, simplifying the complex fracture network into a computable physical model, providing a geometric basis for leakage flow calculation.

[0011] Step three in the above scheme specifically involves: constructing leakage pressure difference calculation models for the different rheological modes identified in step one, based on their radial flow patterns within formation fractures.

[0012] For Newtonian fluids, the leakage pressure difference of parallel plate-shaped geometric cracks is calculated based on their radial flow differential form:

[0013]

[0014] For Bingham fluid, considering its yield stress characteristics, calculate the critical pressure gradient required for the fluid to begin flowing and the corresponding leakage pressure difference:

[0015]

[0016] For a power-law fluid, considering its shear-dilution characteristics, calculate the variation of its effective viscosity in the radial flow field and the corresponding leakage pressure difference.

[0017]

[0018] In the formula: Δ P Leakage pressure differential, MPa; Q For volumetric flow rate, m 3 / s; μ The value is the drilling fluid viscosity, Pa·s; w Where is the crack width, in meters; V t for t Drilling fluid loss at any given time, m 3 ; r w Let be the leakage radius, in meters (m).

[0019] In the above scheme, step four specifically involves: combining the rheological parameters obtained in step one, the fracture width obtained in step two, and the real-time drilling engineering parameters, and substituting them into the leakage pressure differential model of the corresponding rheological mode constructed in step three, to calculate the leakage pressure differential under a given leakage amount or leakage rate, and simultaneously inverting to calculate the dynamic leakage radius or leakage rate of the drilling fluid under a specific pressure differential, and assessing the severity and risk of leakage.

[0020] Beneficial effects

[0021] 1. This invention constructs a leakage pressure difference calculation model that considers the non-Newtonian fluid rheological behavior by coupling the intrinsic relationship between drilling fluid rheological properties and leakage pressure difference. This model achieves accurate characterization of the drilling fluid leakage dynamics process, solves the problem that traditional models do not consider the non-Newtonian properties of drilling fluid, significantly improves the accuracy of leakage pressure difference prediction, and provides a theoretical basis for optimizing drilling fluid density design and controlling leakage risk.

[0022] 2. The method for calculating leakage pressure difference of drilling fluid in fractured formations provided by this invention fully considers the actual rheological properties (yield stress, shear dilution) of drilling fluid and the influence of fracture width on the leakage process, and changes the limitation of simplifying drilling fluid as a Newtonian fluid in traditional methods, thus significantly improving the prediction accuracy of leakage pressure difference.

[0023] 3. The method for calculating the leakage pressure difference of drilling fluid in fractured formations provided by this invention can quickly calculate the leakage pressure difference under different working conditions, provide a quantitative basis for optimizing the drilling fluid density window, and evaluate the effect of plugging operations, which helps to reduce well leakage accidents and reduce drilling costs.

[0024] 4. The parameters required for the drilling fluid leakage pressure differential calculation method in fractured formations provided by this invention (drilling fluid rheological parameters, fracture aperture, etc.) can all be obtained through field logging interpretation or laboratory tests. The calculation method is clear and easy to integrate into the drilling real-time monitoring system to achieve online early warning of well leakage risk. Attached Figure Description

[0025] Figure 1 This is a fitting diagram of the drilling fluid rheological curve of the present invention;

[0026] Figure 2 3D CT model of the core;

[0027] Figure 3 This is a flowchart of the present invention. Detailed Implementation

[0028] The invention will be further described below with reference to the accompanying drawings:

[0029] like Figure 3 As shown, this is the method for calculating the leakage pressure differential of drilling fluid in fractured formations:

[0030] Step 1: Measure the drilling fluid readings at 600 rpm to 3 rpm using a six-speed rotational viscometer, and plot the shear stress-shear rate curve of the measured fluid. Use nonlinear regression to fit the constitutive equations (such as Newtonian, Bingham, and power-law models) that best describe the rheological behavior of the drilling fluid, and obtain the corresponding rheological parameters (such as yield stress, plastic viscosity, consistency coefficient, and flow index). Fit the experimental data using the Newtonian, Bingham, and power-law model rheological equations respectively; select the model with the highest fit as the optimal rheological model.

[0031] Table 1. Rheological equations and rheological parameters for different fluids

[0032]

[0033] Step 2: Using downhole imaging logging data (such as FMI, UBI) or core analysis data, obtain the fracture parameters and fracture width of the target section. For the dominant leakage channel, it is equivalent to a parallel plate-like geometric model, simplifying the complex fracture network into a computable physical model, providing a geometric basis for leakage flow calculation.

[0034] Step 3: For the different rheological modes identified in Step 1, construct calculation models for the leakage pressure difference in radial flow within formation fractures:

[0035] For Newtonian fluids, the leakage pressure difference of parallel plate-shaped geometric cracks is calculated based on their radial flow differential form:

[0036]

[0037] For Bingham fluid, considering its yield stress characteristics, calculate the critical pressure gradient required for the fluid to begin flowing and the corresponding leakage pressure difference:

[0038]

[0039] For a power-law fluid, considering its shear-dilution characteristics, calculate the variation of its effective viscosity in the radial flow field and the corresponding leakage pressure difference:

[0040]

[0041] In the formula: Δ P Leakage pressure differential, MPa; Q For volumetric flow rate, m 3 / s; μ The value is the drilling fluid viscosity, Pa·s; w Where is the crack width, in meters; V t for t Drilling fluid loss at any given time, m 3 ; rw Let be the leakage radius, in meters (m).

[0042] Step 4: Combine the rheological parameters obtained in Step 1, the fracture width obtained in Step 2, and the real-time drilling engineering parameters, and substitute them into the leakage pressure differential model of the corresponding rheological mode constructed in Step 3 to calculate the leakage pressure differential under a given leakage amount or leakage rate. Alternatively, the dynamic leakage radius or leakage rate of the drilling fluid under a specific pressure differential can be calculated in reverse to assess the severity and risk of leakage. Example

[0043] This method for calculating drilling fluid leakage pressure differential in fractured formations:

[0044] Step 1: The on-site three-stage polymer drilling fluid system formulation is as follows: base slurry + 3-5% clay powder + 0.75-1% TBX (coating agent) + 2-3% fluid loss reducer (ammonium salt, CMC) + 2.5-3% anti-collapse agent. The drilling fluid readings at 600 rpm to 3 rpm were measured using a six-speed rotational viscometer, and the results are shown in Table 2. Figure 1 As shown, when the rheological mode of the drilling fluid system is a power-law mode, the adjusted R0 is obtained by using nonlinear regression fitting. 2 The maximum value is 0.9967. At this point, the flowability index is 0.73 and the consistency index is 0.15.

[0045] Table 2 Drilling Fluid Six-Fast Reading Values

[0046] Drilling fluid 52 34 29 17 3 2

[0047] Step 2: Conduct a 3D CT scan experiment on the core samples taken from the lost strata. The 3D CT model of the core is as follows: Figure 2 Based on the maximum sphere filling method for characterizing the crack space, the actual crack width averages 2.6 mm. This experimental result provides reference data for subsequent leakage pressure calculation.

[0048] Step 3: Construct calculation models for leakage pressure differential of drilling fluid flowing radially in formation fractures under different rheological modes. Assume the fractures have a parallel plate-like geometry. t The amount of drilling fluid lost in the fracture at any given time is:

[0049]

[0050] When drilling fluid enters a fracture, the relationship between fracture permeability and fracture width is as follows:

[0051]

[0052] The leakage pressure differential models of fractured formations under different rheological modes are as follows:

[0053] Newtonian fluids

[0054] The one-dimensional differential form of the conventional Darcy's law is:

[0055]

[0056] In the formula: k For penetration rate, m 2 ; A Let m be the cross-sectional area of ​​the flow path. 2 ; dP / dx For pressure gradient, Pa / m.

[0057] For radial flow of fluid near the wellbore, the flow direction is along the radius. r w (Wellbore radius) to r t (Loss radius at time t), cross-sectional area varies with radius: A = 2π rw Darcy's law, in its radial form, becomes:

[0058]

[0059] Separating variables P and r, and integrating, we get:

[0060]

[0061] The leakage pressure differential model for Newtonian fluids in fractured formations is as follows:

[0062]

[0063] Bingham Fluid

[0064] Bingham fluids can be understood as Newtonian fluids with a yield value; therefore, the effect of yield stress needs to be considered in the radial flow Darcy's law model. Let the radius be... r ,width w The fluid ring, when τ = τ 0 At this point, the fluid begins to flow, and the corresponding critical pressure gradient is:

[0065]

[0066] For differential equations from the inner radius r w arrive r t The critical pressure difference can be obtained by integration:

[0067]

[0068] The formation diffusion equation for Bingham fluid can be obtained as follows:

[0069]

[0070] The Bingham fluid fractured formation leakage pressure differential model is as follows:

[0071]

[0072] Power-law fluids

[0073] The main difference between power-law fluids and Newtonian fluids is that the shear stress in power-law fluids is proportional to the nth power of the shear rate. In steady-state flow, the volumetric flow rate is related to the flow velocity as follows: Q = A u ( r ) = 2π rwu ( r Therefore, the effective viscosity of a power-law fluid can be written as:

[0074]

[0075] Substituting into the radial flow Darcy formula, we get:

[0076]

[0077] Separating variables P and r, and integrating, we get:

[0078]

[0079] The formation diffusion equation for power-law fluids can be obtained as follows:

[0080]

[0081] The power-law fluid leakage pressure differential model for fractured formations is as follows:

[0082]

[0083] Step 4: The leakage velocity of the lost well on site is 19.12m. 3 / h, drilling fluid viscosity is 34 mPa·s, leakage rate is 50m 3 The wellbore radius is 0.108 m. Substituting the values ​​into the Newtonian fluid dynamics calculation, the leakage pressure differential is:

[0084]

[0085] Substituting into the power-law fluid fractured formation leakage pressure model, we get:

[0086]

[0087] Loss occurred at a drilling depth of 1947 m, at which point the drilling fluid density was 1.12 g / cm³. The formation pressure equivalent density at this depth was 0.83 g / cm³, resulting in a calculated bottomhole pressure differential of 5.54 MPa. Loss will occur when the bottomhole pressure differential exceeds the leakage pressure differential. Comparison shows that the calculation results from the power-law fluid fractured formation leakage pressure model are more accurate and consistent with the actual field conditions.

Claims

1. A method for calculating the leakage pressure differential of drilling fluid in fractured formations, characterized in that... Includes the following steps: Step 1: Based on drilling fluid rheological experimental data, identify the rheological behavior of drilling fluid in fractured formations. The rheological modes include Newtonian fluid, Bingham fluid, and power-law fluid, and obtain the rheological parameters of the corresponding rheological behavior. The rheological parameters include yield stress, plastic viscosity, consistency coefficient, and flow index. Select the optimal rheological mode. The drilling fluid readings at 600 rpm to 3 rpm were measured using a six-speed rotational viscometer, and the shear stress-shear rate curves of the measured fluid were plotted. Nonlinear regression was used to fit the constitutive equations that best describe the rheological behavior of the drilling fluid, and the corresponding rheological parameters were obtained. The experimental data were fitted using the Newtonian model, Bingham model, and power-law model rheological equations, respectively. The model with the highest fit was selected as the optimal rheological model. Step 2: Using downhole imaging logging data or core analysis data, obtain the fracture parameters of the target section. For the dominant leakage channel, it is equivalent to a parallel plate geometric model, simplifying the complex fracture network into a computable physical model, providing a geometric basis for leakage flow calculation. The fracture parameters include the fracture width. Step 3: Construct a calculation model for leakage pressure difference of drilling fluids with different rheological modes in the radial flow of formation fractures; For the different rheological modes identified in step one, calculation models for leakage pressure differentials in radial flow within formation fractures are constructed respectively: For Newtonian fluids, the leakage pressure difference of parallel plate-shaped geometric cracks is calculated based on their radial flow differential form: ； For Bingham fluid, considering its yield stress characteristics, calculate the critical pressure gradient required for the fluid to begin flowing and the corresponding leakage pressure difference: ； For a power-law fluid, considering its shear-dilution characteristics, calculate the variation of its effective viscosity in the radial flow field and the corresponding leakage pressure difference: ； In the formula: Δ P This refers to the leakage pressure differential; Q Volumetric flow rate; μ The viscosity of the drilling fluid; w The width of the crack; V t for t Drilling fluid loss at any given time; r w The leakage radius; is the yield stress of Bingham fluid; K is the consistency coefficient of power-law fluid; Step 4: Based on real-time drilling engineering parameters, calculate the leakage pressure difference under a given leakage rate and leakage velocity.

2. The method for calculating the leakage pressure difference of drilling fluid in fractured formations according to claim 1, characterized in that: The fourth step specifically involves: combining the rheological parameters obtained in the first step, the fracture width obtained in the second step, and the real-time drilling engineering parameters, and substituting them into the leakage pressure differential model of the corresponding rheological mode constructed in the third step, to calculate the leakage pressure differential under a given leakage amount or leakage rate.

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