CN104732064A - Oil base drilling fluid parameter design method - Google Patents

Abstract

The invention discloses a method for designing oil-based drilling fluid parameters, which comprises the following steps in sequence: testing the physical properties and structural properties of formation rocks through experiments; establishing typical minerals and formations according to the physical properties and structural properties of formation rocks The comprehensive characterization model of rock pore structure and oil-based drilling fluid parameters on the wettability of formation rock and oil-based drilling fluid system, and draw the relationship diagram between oil-based drilling fluid parameters and wettability; establish formation rock and oil-based drilling fluid The wellbore stability mechanical model of the drilling fluid system under wettability conditions, and draw the relationship diagram between the oil-based drilling fluid parameters and the wellbore stability; according to the relationship diagram between the oil-based drilling fluid parameters and the wellbore stability, determine Oil-based drilling fluid parameters. The parameter window of the oil-based drilling fluid designed by the present invention is accurate and reasonable, and can quantitatively evaluate the effect of the oil-based drilling fluid on maintaining well wall stability, prevent the occurrence of downhole complex situations, and reasonably control the cost of the oil-based drilling fluid.

Description

A Design Method of Oil-based Drilling Fluid Parameters

technical field

The invention belongs to the technical field of oil and gas drilling engineering, and relates to a design method of a drilling fluid system, in particular to a design method of parameters of an oil-based drilling fluid.

Background technique

In recent years, wellbore stability has always been a key technical problem restricting oil drilling in my country. In order to maintain the stability of the borehole wall, oil-based drilling fluid is often used for drilling in formations rich in clay minerals with a penetration rate of 90% during drilling. However, for fractured formations with developed fractures, oil-based drilling fluids will still leak into Strata. Especially for mixed-wet formations with a large number of micro-cracks, such as shale formations, mudstone formations, and sandstone formations, the oil-based drilling fluid filtrate is more likely to enter the formation under the action of capillary force, thereby increasing the stress intensity factor at the tip of the fracture , making the fracture expand, which in turn leads to the instability of the borehole wall. From a microcosmic perspective, the interface properties of the boundary layer between oil-based drilling fluid and formation rocks, especially the wettability, is the key to controlling the entry of oil-based drilling fluid into formation rocks, as well as all physical interactions between oil-based drilling fluids and formation rocks. The key to chemistry.

Since the change of wettability between formation rock and oil-based drilling fluid system will affect the stress intensity factor of the fracture tip, based on the theory of fracture mechanics, when the stress intensity factor exceeds the fracture toughness of formation rock, the fracture will expand and the wellbore will become unstable. The wettability of formation rock and oil-based drilling fluid system needs a safety window. The characteristics of the oil-based drilling fluid system directly affect the wettability of the formation rock and the oil-based drilling fluid system to a large extent, and then affect the stability of the wellbore wall. Oil-based drilling fluid parameters are of great significance for maintaining wellbore stability.

The invention patent with application publication number CN103045198A discloses an anti-leakage drilling fluid system used in natural gas wells. , Calcium Carbonate 1-5, Potassium Chloride 1-5, the balance is water, the above proportions are all calculated by weight, the unit is kilogram, and the drilling fluid is prepared according to the above formula and used for drilling.

The invention patent with application publication number CN103045194A discloses a reservoir protection drilling fluid system used in natural gas wells. Its formula is bentonite 1-5, ammonium salt 0.1-1, coating agent 0.1-1, sulfonated asphalt 1-5 , sulfonated lignite 1-5, film-forming agent 0.5-5, calcium carbonate 1-5, potassium chloride 1-5, the balance is water, the above ratios are calculated by weight, the unit is kilogram, and the drilling fluid is prepared according to the above formula And used in the drilling process.

The drilling fluid systems of the above two patents both have the advantages of small water loss, good rheological properties, and the ability to keep the wellbore stable. In addition, the performance of the drilling fluid may be too high, resulting in an increase in cost. Therefore, there is an urgent need to develop a design method for drilling fluid parameters to keep the wellbore stable by controlling the drilling fluid parameters, which has important social and economic significance for the development of my country's oil drilling industry.

Contents of the invention

In order to solve the problems in the prior art, the present invention provides a method for designing oil-based drilling fluid parameters, which comprises the following steps in sequence:

Step 1: Testing the physical and structural properties of formation rocks through experiments;

Step 2: According to the physical and structural properties of formation rocks, establish a comprehensive characterization model of typical minerals, pore structure of formation rocks, and oil-based drilling fluid parameters for the wettability of formation rocks and oil-based drilling fluid systems, and draw oil-based drilling The relationship between liquid parameters and wettability;

Step 3: Establish the wellbore stability mechanical model of the formation rock and oil-based drilling fluid system under wettability conditions, and draw the relationship diagram between the oil-based drilling fluid parameters and the wellbore stability;

Step 4: Determine the parameters of the oil-based drilling fluid according to the relationship diagram between the parameters of the oil-based drilling fluid and the stability of the borehole wall.

The design method of the oil-based drilling fluid parameters of the present invention is to design the parameters of the oil-based drilling fluid based on the characteristics of the formation and the interface between the formation and the fluid, so that the design of the parameters of the oil-based drilling fluid has a more scientific and theoretical basis, so as to effectively prevent the oil-based drilling fluid from The instability of the wall can prevent the occurrence of downhole complex situations, and at the same time avoid the excessive performance of oil-based drilling fluid, and reasonably control the cost of oil-based drilling fluid.

Preferably, in step 1, at least ten formation rocks are taken, and their physical properties and structural properties are tested respectively.

In any of the above options, it is preferred that the mineral composition of the formation rock is tested by X-ray diffraction test. The X-ray diffraction method has the advantages of no damage to formation rock samples, no pollution, fast, and high measurement accuracy of mineral components.

In any of the above schemes, it is preferred to use pyrolysis test and vitrinite reflectance test to test the total organic carbon content (TOC), kerogen type and maturity of formation rocks. In the pyrolysis test, the amount of formation rock samples used is small, the operation is simple, fast, the analysis cost is low, and the test results are accurate, which can evaluate the total organic carbon content and kerogen type of formation rocks. Vitrinite reflectance test is used to test the maturity of formation rocks. The thermal evolution process of organic matter is closely related to the evolution process of vitrinite, so the reflectance of vitrinite is a good indicator of the maturity of organic matter. The deeper the thermal metamorphism of organic matter, the greater the reflectance of vitrinite.

In any of the above schemes, preferably, the pore distribution of formation rocks is tested by scanning electron microscopy, transmission electron microscopy, and computer X-ray tomography. With the help of scanning electron microscope (SEM) and transmission electron microscope (TEM), the two-dimensional pore distribution characteristics in formation rocks can be qualitatively observed; with the help of electronic computer X-ray tomography (CT), the three-dimensional pore distribution characteristics in formation rocks can be qualitatively observed .

In any of the above schemes, preferably, the porosity of the formation rock is tested by using a focused ion beam test or a nitrogen adsorption test. With the help of focused ion beam (FIB) test and nitrogen adsorption test, the porosity of formation rocks can be quantitatively characterized.

In any of the above schemes, preferably, the fracture toughness of the formation rock is tested by using the Brazilian split test.

Preferably in any of the above schemes, in step 2, the establishment of a comprehensive characterization model for the wettability of the formation rock and oil-based drilling fluid system by the typical minerals, the pore structure of the formation rock, and the parameters of the oil-based drilling fluid is carried out sequentially. The sequence consists of the following steps:

Step 1: Make a ternary phase diagram according to the weight percentage of the three typical minerals of silicate minerals, carbonate minerals and clay minerals, analyze the mineral components of the measured Classify the falling points in the phase diagram;

Step 2: prepare standard measurement surfaces of typical mineral formation rocks respectively;

Step 3: Measure the contact angle of the standard measurement surface of typical mineral formation rocks under the action of oil-based drilling fluid, and combine the test data of total organic carbon content, kerogen type, and pore structure of the corresponding formation rocks to analyze typical minerals , The influence of total organic carbon content and porosity on the wettability of formation rock and oil-based drilling fluid system;

Step 4: Prepare oil-based drilling fluids with different properties by adjusting the oil-water ratio and the amount of emulsifier added, and measure their demulsification voltage, viscosity, pH value, API filter vector (filter vector at room temperature 0.7MPa), HTHP filter vector (high temperature and high pressure filter vector);

Step 5: Measure the contact angle of the standard measurement surface of typical mineral formation rocks under the action of oil-based drilling fluids with different properties, and analyze the influence of oil-based drilling fluid parameters on the wettability of the formation rock and oil-based drilling fluid system;

Step 6: Based on the test data of the weight percentage of typical minerals, total organic carbon content, porosity, oil-based drilling fluid parameters, and contact angle, a comprehensive characterization model for the wettability of the formation rock and oil-based drilling fluid system is established.

In any of the above schemes, it is preferable to analyze the mineral components of the measured formation rocks, at least one type of typical minerals.

In any of the above schemes, it is preferable to analyze the mineral components of the measured formation rocks, which are three types of typical minerals.

Take at least ten formation rocks, test their mineral components respectively, and classify them according to the falling points of the mineral components in the ternary phase diagram, and the mineral components are calculated by weight percentage. The three typical minerals are silicate minerals, carbonate minerals, and clay minerals. If which type of mineral component is dominant in the formation rock, which type of mineral formation rock is the formation rock. Quartz, potassium feldspar, and plagioclase are silicate minerals; calcite and dolomite are carbonate minerals.

In any of the above schemes, it is preferred that the shape of the standard measurement sample of the typical mineral formation rock is cylindrical.

In any of the above schemes, preferably, the upper and lower end faces of the cylinder are parallel.

In any of the above schemes, preferably, the upper and lower end surfaces of the cylinder are mechanically polished.

In any of the above schemes, preferably, the upper and lower end surfaces of the cylinder are subjected to argon ion polishing treatment.

In any of the above schemes, preferably, the height of the cylinder is not greater than 20mm.

In any of the above solutions, it is preferred that the diameter of the cylinder is at least 10 mm.

In order to ensure the measurement accuracy, the two end faces of the cylindrical measurement sample should be kept parallel, and the two end faces should be mechanically polished or argon ion polished to ensure that the end faces are still smooth and free of scratches when magnified 1000 times under an optical microscope.

In any of the above schemes, it is preferred that the contact angle of the standard measurement surface of typical mineral formation rocks under the action of oil-based drilling fluid is measured by video optics test. In the video optics experiment, the formation rock sample is positioned triaxially, and the measurement is accurate.

In any of the above schemes, it is preferred that the oil-based drilling fluid contains diesel oil, water, primary emulsifier, secondary emulsifier, calcium chloride, organic soil, fluid loss reducer I, fluid loss reducer II, alkali Degree control agent, weighting agent. The main emulsifier can choose VERSAMUL, the auxiliary emulsifier can choose VERSACOAT HF, the organic soil can choose VG-PLUS, the fluid loss reducer I can choose VERSATROL, the fluid loss reducer II can choose ECOTROLRD, the alkalinity control agent can choose calcium oxide, The weighting agent can choose barite.

In any of the above schemes, preferably, the parameters of the oil-based drilling fluid are demulsification voltage, pH value, oil-water ratio, and emulsifier addition. The above four parameters are key parameters of the oil-based drilling fluid to be designed in the present invention. The oil-water ratio is the ratio of diesel oil to water, and the amount of emulsifier added is the main emulsifier and the auxiliary emulsifier.

When configuring oil-based drilling fluid, it is necessary to test the following properties of oil-based drilling fluid: demulsification voltage (ES), pH value, viscosity (AV), API filter vector, HTHP filter vector. Since the AV, API, and HTHP of the oil-based drilling fluid have industry standards and must meet corresponding requirements, it is not necessary to use the design method of the present invention to design these three parameters, only key parameters need to be designed.

Preferably in any of the above schemes, the comprehensive characterization model of the wettability of the formation rock and oil-based drilling fluid system is

θ=F(ES, PH, O/W, W _e , TOC, φ, W ₁ , W ₂ , W ₃ )

Among them, θ—contact angle between formation rock and oil-based drilling fluid system, °;

ES——emulsion breaking voltage, V;

PH——PH value;

O/W——oil-water ratio;

W _e - the amount of emulsifier added, %;

TOC—total organic carbon content, %;

φ——porosity, %;

W ₁ , W ₂ , W ₃ ——weight percentage of three typical minerals, %.

Preferably in any of the above schemes, in step 3, the establishment of the wellbore stability mechanical model of the formation rock and oil-based drilling fluid system under wettability conditions includes the following steps in sequence:

Step 1: Calculate the stress intensity factor at the tip of the Type I fracture around the wellbore;

Step 2: According to the theory of fracture mechanics, establish the wellbore stability mechanical model of formation rock and oil-based drilling fluid system under wettability conditions;

Step 3: Combining the mechanical model of wellbore stability and the comprehensive characterization model of wettability of formation rock and oil-based drilling fluid system, analyze the influence of oil-based drilling fluid parameters on wellbore stability, and draw the relationship between oil-based drilling fluid parameters and wellbore stability relationship diagram.

In any of the above schemes, it is preferred that the formula for calculating the stress intensity factor of the tip of the I-type fracture around the wellbore is:

${\mathrm{<span\; class="notranslate">\; K</span>}}_{\mathrm{<span\; class="notranslate">\; I</span>}}<span\; class="notranslate">\; =</span><span\; class="notranslate">\; -</span>\mathrm{<span\; class="notranslate">\; \&sigma;</span>}\sqrt{\mathrm{<span\; class="notranslate">\; \&pi;H</span>}}<span\; class="notranslate">\; +</span>\frac{\mathrm{<span\; class="notranslate">\; 2</span>}{\mathrm{<span\; class="notranslate">\; P</span>}}_{\mathrm{<span\; class="notranslate">\; f</span>}}}{\sqrt{\mathrm{<span\; class="notranslate">\; \&pi;H</span>}}}\mathrm{<span\; class="notranslate">\; h</span>}\mathrm{<span\; class="notranslate">\; arcsin</span>}\frac{\mathrm{<span\; class="notranslate">\; 1</span>}}{\mathrm{<span\; class="notranslate">\; h</span>}}<span\; class="notranslate">\; +</span>\frac{\mathrm{<span\; class="notranslate">\; 2</span>}\mathrm{<span\; class="notranslate">\; \&gamma;\; COS</span>}<span\; class="notranslate">\; (</span>\mathrm{<span\; class="notranslate">\; \&theta;</span>}<span\; class="notranslate">\; +</span>\mathrm{<span\; class="notranslate">\; \&beta;</span>}<span\; class="notranslate">\; )</span>\mathrm{<span\; class="notranslate">\; COS\&theta;</span>}}{\mathrm{<span\; class="notranslate">\; \&omega;</span>}\sqrt{\mathrm{<span\; class="notranslate">\; \&pi;H</span>}}}\sqrt{\frac{\mathrm{<span\; class="notranslate">\; h</span>}<span\; class="notranslate">\; +</span>\mathrm{<span\; class="notranslate">\; L</span>}}{\mathrm{<span\; class="notranslate">\; h</span>}<span\; class="notranslate">\; -</span>\mathrm{<span\; class="notranslate">\; L</span>}}}$

Among them, σ——earth stress, MPa;

P _f ——liquid column pressure, MPa;

γ—interfacial tension between oil-based drilling fluid and formation water, mN/m;

β—the angle between the fracture wall and the fracture central axis, °;

ω——crack width, m;

θ—contact angle between formation rock and oil-based drilling fluid system, °;

H——the width at half maximum of the crack, m;

L—the distance from the microfracture center to the drilling fluid front of the fracture tip, m.

In any of the above schemes, preferably, the wellbore stability mechanical model of the formation rock and oil-based drilling fluid system under wettability conditions is K _I ≤ K _IC ,

Among them, K _I —stress intensity factor of type I fracture tip around the wellbore;

K _IC ——fracture toughness of formation rock.

In any of the above schemes, it is preferred that the oil-based drilling fluid is used in a shale formation in Sichuan, and its parameter window is that the oil-water ratio is 80-95:5-20, and the main emulsifier addition is 0.8-2.5 %, the amount of auxiliary emulsifier added is 1.3-2.8%, the pH value is 8.0-9.5, and the demulsification voltage is 400-853V.

In any of the above schemes, it is preferred that the oil-based drilling fluid is used in a mudstone formation in Karamay, Xinjiang, and its parameter window is that the oil-water ratio is 80-90:10-20, and the main emulsifier addition is 1.0-2.2 %, the amount of co-emulsifier added is 1.6-3.1%, the pH value is 7.0-10, and the demulsification voltage is 400-841V.

In any of the above schemes, it is preferred that the oil-based drilling fluid is used in a sandstone formation in Yunnan, and its parameter window is that the oil-water ratio is 75-85:15-25, and the main emulsifier addition is 0.95-2.0%. , The amount of auxiliary emulsifier added is 1.4-2.7%, the pH value is 7.0-9.0, and the demulsification voltage is 400-940V.

The present invention uses the wetting theory to design the key parameters of oil-based drilling fluid, first characterizes the physical and structural properties of formation rocks through X-ray diffraction technology, micro-area image analysis technology, fluid injection technology, etc., and then uses advanced video optical technology to study The impact of the typical mineral characteristics, structural characteristics and key parameters of oil-based drilling fluid on the wettability of formation rock and oil-based drilling fluid system, establish a comprehensive characterization model, and then establish a comprehensive characterization model based on the theory of fracture mechanics to consider the formation rock and oil-based drilling fluid Wellbore stability mechanics model for system wettability. Based on the characteristics of the drilled formation rock, the above two models are comprehensively applied to study the influence of the key parameters of oil-based drilling fluid on the stability of the wellbore, and the relationship between the key parameters of the oil-based drilling fluid and the stability of the wellbore is established, and based on the relationship diagram Design the window of key parameters of oil-based drilling fluid to effectively maintain the stability of the wellbore, prevent the occurrence of downhole complex situations, and reasonably control the cost of oil-based drilling fluid. The design method of the present invention is simple and easy to operate; the designed window of the key parameters of the oil-based drilling fluid is accurate and reasonable, and the window is wide, which is easy to operate on site; it can quantitatively evaluate the effect of the oil-based drilling fluid to maintain the stability of the borehole wall, which is of great importance to my country The development of oil drilling industry has important social and economic significance.

Description of drawings

Fig. 1 is a flow chart of a preferred embodiment according to the design method of oil-based drilling fluid parameters of the present invention;

Fig. 2 is the ternary phase diagram of formation rock mineral composition according to the embodiment shown in Fig. 1 of the design method of oil-based drilling fluid parameters of the present invention;

Fig. 3 is the contact angle under the effect of oil-based drilling fluid on the standard measurement surfaces of three typical mineral formation rocks according to the design method of oil-based drilling fluid parameters of the present invention shown in Fig. 1;

Among them, (a) and (b) are the contact angles of the standard measurement surfaces of silicate minerals and carbonate mineral formation rocks under the action of oil-based drilling fluid, respectively.

Fig. 4 is the embodiment shown in Fig. 1 according to the design method of oil-based drilling fluid parameters of the present invention, under the pH value of 6.5 and different demulsification voltages, the relationship diagram between the contact angle and the silicate mineral content;

Fig. 5 is according to the embodiment shown in Fig. 1 of the design method of oil-based drilling fluid parameters of the present invention, when the formation petrophysical properties and structural properties are constant, the relationship between the contact angle and demulsification voltage of oil-based drilling fluid under different pH values relationship diagram;

Fig. 6 is according to the embodiment shown in Fig. 1 of the design method of oil-based drilling fluid parameters of the present invention, when formation petrophysical properties and structural properties are constant, the relationship between the demulsification voltage and pH value of oil-based drilling fluid and the stress intensity factor relation chart;

Fig. 7 is a ternary phase diagram of formation rock mineral components according to another preferred embodiment of the method for designing oil-based drilling fluid parameters of the present invention;

Fig. 8 is a relation diagram between contact angle and silicate mineral content under the pH value of 6.5 and different demulsification voltages according to the embodiment shown in Fig. 7 according to the design method of oil-based drilling fluid parameters of the present invention;

Fig. 9 is the embodiment shown in Fig. 7 according to the design method of oil-based drilling fluid parameters of the present invention. When the formation petrophysical properties and structural properties are constant, the relationship between the contact angle and demulsification voltage of oil-based drilling fluid under different pH values relationship diagram;

Fig. 10 is according to the embodiment shown in Fig. 7 of the design method of oil-based drilling fluid parameters of the present invention, when the formation petrophysical properties and structural properties are constant, the relationship between the demulsification voltage and pH value of the oil-based drilling fluid and the stress intensity factor relation chart;

Fig. 11 is a ternary phase diagram of formation rock mineral components according to another preferred embodiment of the method for designing oil-based drilling fluid parameters of the present invention;

Fig. 12 is a relationship diagram between contact angle and silicate mineral content under the pH value of 6.5 and different demulsification voltages according to the embodiment shown in Fig. 11 according to the design method of oil-based drilling fluid parameters of the present invention;

Fig. 13 is the embodiment shown in Fig. 11 according to the design method of oil-based drilling fluid parameters of the present invention. When the formation petrophysical properties and structural properties are constant, the relationship between the contact angle and demulsification voltage of oil-based drilling fluid under different pH values relationship diagram;

Fig. 14 is according to the embodiment shown in Fig. 11 of the design method of oil-based drilling fluid parameters of the present invention, when the formation petrophysical properties and structural properties are constant, the relationship between the demulsification voltage and pH value of the oil-based drilling fluid and the stress intensity factor relation chart.

Detailed ways

In order to further understand the content of the present invention, the present invention will be described in detail below in conjunction with specific examples.

Embodiment one:

As shown in Fig. 1, in this embodiment, a shale formation in a block in Sichuan, China is selected, and the key parameter window of the oil-based drilling fluid is designed based on the wetting theory of the formation rock and the oil-based drilling fluid system. A method for designing oil-based drilling fluid parameters, which comprises the following steps in sequence:

Step 1: Test the physical and structural properties of formation rocks through experiments.

Ten shale formation samples were taken to test their physical and structural properties. X-ray diffraction test is used to test the mineral composition of formation rocks; pyrolysis test and vitrinite reflectance test are used to test the total organic carbon content (TOC), kerogen type, maturity of formation rocks; with the help of scanning electron microscope (SEM) and transmission electron microscope (TEM) to qualitatively observe the two-dimensional pore distribution characteristics in formation rocks; with the help of computer X-ray tomography (CT), to qualitatively observe the three-dimensional pore distribution characteristics in formation rocks;

Focused ion beam (FIB) test and nitrogen adsorption test were used to quantitatively characterize the porosity of formation rocks; the Brazilian splitting test was used to test the fracture toughness of formation rocks. The pore distribution characteristics of the ten formation rock samples are that in the brittle minerals, micro-cracks are developed, and organic matter pores are also relatively developed. After excluding samples with large errors from the ten formation rock samples measured, the remaining samples were used for subsequent design. In this embodiment, the data of three typical samples are selected from the remaining samples as an example. The mineral composition, total organic carbon content, kerogen type, and vitrinite reflectance test results of the three formation rock samples are shown in Table 1.1. The porosity and fracture toughness test results of the three formation rock samples are shown in Table 1.2.

Table 1.1 Test results of physical properties of three formation rock samples

Table 1.2 Porosity and fracture toughness test results of three formation rock samples

Sample serial number Porosity(%) Fracture toughness (MPa·m ^1/2 ) 1# 4.02 0.63 2# 4.61 0.60 3# 2.54 0.85

Step 2: According to the physical and structural properties of formation rocks, establish a comprehensive characterization model of typical minerals, pore structure of formation rocks, and oil-based drilling fluid parameters for the wettability of formation rocks and oil-based drilling fluid systems, and draw oil-based drilling A plot of the relationship between liquid parameters and wettability.

The establishment of a comprehensive characterization model of typical minerals, pore structure of formation rocks, and oil-based drilling fluid parameters on the wettability of formation rocks and oil-based drilling fluid systems includes the following steps in sequence:

(1) Make a ternary phase diagram according to the weight percentages of the three typical minerals of silicate minerals, carbonate minerals and clay minerals, as shown in Figure 2. The weight percentages of the three typical minerals are W ₁ , W ₂ , W ₃ , analyze the mineral components of the three strata rocks that have been measured, and classify them according to the falling points of the mineral components in the ternary phase diagram. The 1# sample is a silicate mineral formation rock, the 2# sample is a carbonate mineral formation rock, and the 3# sample is a clay mineral formation rock.

(2) Prepare standard measurement surfaces for silicate mineral formation rocks, carbonate mineral formation rocks, and clay mineral formation rocks, respectively, for wettability measurement.

The standard measurement samples of the three types of typical mineral formation rocks are cylindrical in shape, and their upper and lower end faces are parallel. The cylindrical sample has a height of 20 mm and a diameter of 10 mm. The upper and lower end surfaces of the cylinder need to be mechanically polished or argon ion polished to ensure that the end surfaces are still smooth and scratch-free when magnified 1000 times under an optical microscope.

(3) Measure the contact angle θ of the standard measurement surfaces of silicate mineral formation rocks, carbonate mineral formation rocks, and clay mineral formation rocks under the action of oil-based drilling fluid by video optical test, as shown in Figure 3, and Combined with the test data of total organic carbon content, kerogen type and pore structure of the corresponding formation rocks, the influence of typical minerals, total organic carbon content and porosity on the wettability of formation rocks and oil-based drilling fluid system is analyzed.

Analysis of the formation rock samples in this embodiment shows that different typical minerals (silicate minerals, carbonate minerals, clay minerals) and organic matter have a significant impact on the interface properties of the formation rock and oil-based drilling fluid system, but the degree of influence and affect in different ways. For example, as the content of silicate minerals or carbonate minerals increases, the contact angle gradually increases, while with the increase of organic matter content or maturity, the contact angle tends to decrease. Fig. 4 is a graph showing the relationship between the contact angle and the content of silicate minerals under the pH value of 6.5 and different demulsification voltages.

(4) Prepare oil-based drilling fluids with different properties by adjusting the oil-water ratio and the amount of emulsifier added, and measure their demulsification voltage, viscosity, pH value, API filter vector, and HTHP filter vector.

The oil-based drilling fluid components of the present embodiment are as follows, calculated in weight percent: diesel oil, water, main emulsifier (VERSAMUL) 1.7%, auxiliary emulsifier (VERSACOAT HF) 2.3%, calcium chloride 4.3%, organic soil (VG -PLUS) 0.6%, fluid loss reducer I (VERSATROL) 2.8%, fluid loss reducer II (ECOTROL RD) 0.15%, alkalinity control agent (calcium oxide) 2.8%, weighting agent (barite).

Adjust the oil-water ratio and the amount of emulsifier added to configure oil-based drilling fluids with different properties. The key parameters of oil-based drilling fluid are demulsification voltage (ES), pH value, oil-water ratio (O/W), emulsifier addition amount (W _e ). The amount of emulsifier added is the amount of main emulsifier added and the amount of auxiliary emulsifier added.

(5) Using video optics test to measure the contact angle of the standard measurement surface of typical mineral formation rocks under the action of oil-based drilling fluid with different properties, and analyze the influence of oil-based drilling fluid parameters on the wettability of formation rock and oil-based drilling fluid system Influence.

Analysis of the formation rock samples in this embodiment shows that when the characteristics of the formation rock are constant, the contact angle between the formation rock and the oil-based drilling fluid system decreases with the increase of the oil-water ratio, the amount of emulsifier added, and the demulsification voltage. However, the fracture strength factor at the tip of the fracture increases, and the magnitude of the fracture strength factor increases at different pH values and fluid loss.

(6) Based on the test data of typical mineral weight percentage, total organic carbon content, porosity, oil-based drilling fluid parameters, and contact angle, a comprehensive characterization model for the wettability of formation rock and oil-based drilling fluid system was established.

The establishment of the comprehensive characterization model takes into account the characteristics of formation rock mineral components, pore structure characteristics and performance parameters of oil-based drilling fluid.

In this example, the comprehensive characterization model for the wettability of formation rock and oil-based drilling fluid system is

θ=F(ES, PH, O/W, W _e , TOC, φ, W ₁ , W ₂ , W ₃ )

Among them, θ—contact angle between formation rock and oil-based drilling fluid system, °;

ES——emulsion breaking voltage, V;

PH——PH value;

O/W——oil-water ratio;

W _e - the amount of emulsifier added, %;

TOC—total organic carbon content, %;

φ——porosity, %;

W ₁ , W ₂ , W ₃ ——weight percentage of three typical minerals, %.

Fig. 5 is a graph showing the relationship between the contact angle and the demulsification voltage of the oil-based drilling fluid at different pH values when the physical and structural properties of the formation rock are constant.

Step 3: Establish the wellbore stability mechanical model of the formation rock and oil-based drilling fluid system under wettability conditions, and draw the relationship diagram between the oil-based drilling fluid parameters and the wellbore stability.

The establishment of the wellbore stability mechanical model of the formation rock and oil-based drilling fluid system under wettability conditions includes the following steps in sequence:

(1) Calculate the stress intensity factor at the tip of the type I fracture around the wellbore.

During the drilling process, the oil-based drilling fluid enters the formation rock along the bedding plane or fracture, and generates capillary force at the fracture tip of the micro-fracture, changing the stress state of the fracture tip.

According to the geometric relationship, when the fluid is oil-based drilling fluid, the capillary force is Among them, γ—interfacial tension between oil-based drilling fluid and formation water, mN/m;

β—the angle between the fracture wall and the fracture central axis, °;

ω——crack width, m;

When drilling with oil-based drilling fluid, the formula for calculating the stress intensity factor at the tip of type I fractures around the wellbore is

${\mathrm{<span\; class="notranslate">\; K</span>}}_{\mathrm{<span\; class="notranslate">\; I</span>}}<span\; class="notranslate">\; =</span><span\; class="notranslate">\; -</span>\mathrm{<span\; class="notranslate">\; \&sigma;</span>}\sqrt{\mathrm{<span\; class="notranslate">\; \&pi;H</span>}}<span\; class="notranslate">\; +</span>\frac{\mathrm{<span\; class="notranslate">\; 2</span>}{\mathrm{<span\; class="notranslate">\; P</span>}}_{\mathrm{<span\; class="notranslate">\; f</span>}}}{\sqrt{\mathrm{<span\; class="notranslate">\; \&pi;H</span>}}}\mathrm{<span\; class="notranslate">\; h</span>}\mathrm{<span\; class="notranslate">\; arcsin</span>}\frac{\mathrm{<span\; class="notranslate">\; 1</span>}}{\mathrm{<span\; class="notranslate">\; h</span>}}<span\; class="notranslate">\; +</span>\frac{\mathrm{<span\; class="notranslate">\; 2</span>}\mathrm{<span\; class="notranslate">\; \&gamma;\; COS</span>}<span\; class="notranslate">\; (</span>\mathrm{<span\; class="notranslate">\; \&theta;</span>}<span\; class="notranslate">\; +</span>\mathrm{<span\; class="notranslate">\; \&beta;</span>}<span\; class="notranslate">\; )</span>\mathrm{<span\; class="notranslate">\; COS\&theta;</span>}}{\mathrm{<span\; class="notranslate">\; \&omega;</span>}\sqrt{\mathrm{<span\; class="notranslate">\; \&pi;H</span>}}}\sqrt{\frac{\mathrm{<span\; class="notranslate">\; h</span>}<span\; class="notranslate">\; +</span>\mathrm{<span\; class="notranslate">\; L</span>}}{\mathrm{<span\; class="notranslate">\; h</span>}<span\; class="notranslate">\; -</span>\mathrm{<span\; class="notranslate">\; L</span>}}}$

Among them, σ——earth stress, MPa;

P _f ——liquid column pressure, MPa;

γ—interfacial tension between oil-based drilling fluid and formation water, mN/m;

β—the angle between the fracture wall and the fracture central axis, °;

ω——crack width, m;

θ—contact angle between formation rock and oil-based drilling fluid system, °;

H—the half-height width of the crack, m;

L—the distance from the microfracture center to the drilling fluid front of the fracture tip, m.

(2) According to the theory of fracture mechanics, the wellbore stability mechanics model of formation rock and oil-based drilling fluid system under wettability conditions is established.

When the oil-based drilling fluid enters the formation rock, the contact angle between the formation rock and the oil-based drilling fluid system will affect the stress intensity factor of type I fractures. According to the analysis of fracture mechanics, when the stress intensity factor is greater than the fracture toughness, the fracture will expand. The well wall is unstable. In order to keep the wellbore stable and prevent downhole complex situations, the contact angle between the formation rock and the oil-based drilling fluid system must be within a safe range to ensure that the stress intensity factor is smaller than the fracture toughness. Therefore, the wellbore stability mechanical model of formation rock and oil-based drilling fluid system under wettability condition is K _I ≤ K _IC ,

Among them, K _I —stress intensity factor of type I fracture tip around the wellbore;

K _IC ——fracture toughness of formation rock.

(3) Combined with the mechanical model of wellbore stability and the comprehensive characterization model of wettability of formation rock and oil-based drilling fluid system, the influence of oil-based drilling fluid parameters on wellbore stability was analyzed, and the relationship between oil-based drilling fluid parameters and wellbore stability was drawn. relationship diagram.

Fig. 6 is a graph showing the relationship between the demulsification voltage and pH value of the oil-based drilling fluid and the stress intensity factor when the rock physical properties and structural properties of the formation are constant.

Step 4: Determine the parameters of the oil-based drilling fluid according to the relationship diagram between the parameters of the oil-based drilling fluid and the stability of the borehole wall.

In this implementation, the oil-based drilling fluid is used in a shale formation in Sichuan. The key parameter window is: the oil-water ratio is 80-95:5-20, the main emulsifier is 0.8-2.5%, and the auxiliary emulsifier is 0.8-2.5%. 1.3-2.8%, PH value 8.0-9.5, demulsification voltage 400-853V.

Embodiment two:

In this example, the mudstone formation in a block in Karamay, Xinjiang is selected, and the key parameter window of oil-based drilling fluid is designed based on the wetting theory of formation rock and oil-based drilling fluid system. The design method is the same as that of Example 1.

the difference is:

Twenty mudstone formation samples were taken, and their physical properties and structural properties were tested respectively. After excluding samples with large errors from the twenty formation rock samples measured, the remaining samples were used for subsequent design. In this embodiment, the data of three typical samples are selected from the remaining samples as an example. The mineral composition, total organic carbon content, kerogen type, and vitrinite reflectance test results of the three formation rock samples are shown in Table 2.1. The porosity and fracture toughness test results of the three formation rock samples are shown in Table 2.2.

Table 2.1 Test results of physical properties of three formation rock samples

Table 2.2 Porosity and fracture toughness test results of three formation rock samples

Sample serial number Porosity(%) Fracture toughness (MPa·m ^1/2 ) 1# 4.32 0.53 2# 4.51 0.63 3# 5.54 0.58

According to the weight percentages of the three typical minerals of silicate minerals, carbonate minerals and clay minerals, a ternary phase diagram is drawn for the formation rocks, as shown in Figure 7. The weight percentages of the three typical minerals are W ₁ , W ₂ , W ₃ , analyze the mineral components of the three strata rocks that have been measured, and classify them according to the falling points of the mineral components in the ternary phase diagram. 1# sample and 2# sample are both silicate mineral formation rocks, and 3# sample is carbonate mineral formation rock.

The standard measurement samples of two types of typical mineral formation rocks are cylindrical in shape, and their upper and lower end faces are parallel. The cylindrical sample has a height of 15 mm and a diameter of 15 mm. The upper and lower end surfaces of the cylinder need to be mechanically polished or argon ion polished to ensure that the end surfaces are still smooth and scratch-free when magnified 1000 times under an optical microscope.

Analysis of the formation rock samples in this embodiment shows that different typical minerals (silicate minerals, carbonate minerals, clay minerals) and organic matter have a significant impact on the interface properties of the formation rock and oil-based drilling fluid system, but the degree of influence and affect in different ways. Fig. 8 is a graph showing the relationship between the contact angle and the content of silicate minerals at a pH value of 6.5 and different demulsification voltages.

The oil-based drilling fluid components of the present embodiment are as follows, calculated in weight percent: diesel oil, water, main emulsifier (VERSAMUL) 1.4%, auxiliary emulsifier (VERSACOAT HF) 2.1%, calcium chloride 5.0%, organic soil (VG -PLUS) 0.7%, fluid loss reducer I (VERSATROL) 2.4%, fluid loss reducer II (ECOTROL RD) 0.25%, alkalinity control agent (calcium oxide) 3.0%, weighting agent (barite).

Adjust the oil-water ratio and the amount of emulsifier added to configure oil-based drilling fluids with different properties. The key parameters of oil-based drilling fluid are demulsification voltage (ES), pH value, oil-water ratio (O/W), emulsifier addition amount (W _e ). The amount of emulsifier added is the amount of main emulsifier added and the amount of auxiliary emulsifier added.

Fig. 9 is a graph showing the relationship between the contact angle and the demulsification voltage of the oil-based drilling fluid at different pH values when the physical and structural properties of the formation rock are constant.

Fig. 10 is a graph showing the relationship between the demulsification voltage and pH value of the oil-based drilling fluid and the stress intensity factor when the rock physical properties and structural properties of the formation are constant.

In this implementation, the oil-based drilling fluid is used in a mudstone formation in Karamay, Xinjiang. The key parameter window is: the oil-water ratio is 80-90:10-20, the addition amount of the main emulsifier is 1.0-2.2%, and the addition amount of the auxiliary emulsifier is 1.6-3.1%, PH value 7.0-10, demulsification voltage 400-841V.

Embodiment three:

In this embodiment, a sandstone formation in a block in Yunnan, China is selected, and the key parameter window of oil-based drilling fluid is designed based on the wetting theory of formation rock and oil-based drilling fluid system. The design method is the same as that of Example 1, except that:

Twenty-five sandstone formation samples were taken, and their physical properties and structural properties were tested respectively. After excluding samples with large errors from the twenty-five formation rock samples measured, the remaining samples were used for subsequent design. In this embodiment, the data of three typical samples are selected from the remaining samples as an example. The mineral composition, total organic carbon content, kerogen type, and vitrinite reflectance test results of the three formation rock samples are shown in Table 3.1. The porosity and fracture toughness test results of the three formation rock samples are shown in Table 3.2.

Table 3.1 Test results of physical properties of three formation rock samples

Table 3.2 Porosity and fracture toughness test results of three formation rock samples

Sample serial number Porosity(%) Fracture toughness (MPa·m ^1/2 ) 1# 5.72 0.43 2# 6.21 0.72 3# 5.64 0.67

According to the weight percentage of the three typical minerals of silicate minerals, carbonate minerals and clay minerals, a ternary phase diagram is drawn for the formation rocks, as shown in Figure 11. The weight percentages of the three typical minerals are W ₁ , W ₂ , W ₃ , analyze the mineral components of the three strata rocks that have been measured, and classify them according to the falling points of the mineral components in the ternary phase diagram. 1# sample, 2# sample, and 3# sample are all silicate mineral formation rocks.

The shape of a standard measurement sample of a typical mineral stratum rock is cylindrical, and its upper and lower end faces are parallel. The cylindrical sample has a height of 10 mm and a diameter of 20 mm. The upper and lower end surfaces of the cylinder need to be mechanically polished or argon ion polished to ensure that the end surfaces are still smooth and scratch-free when magnified 1000 times under an optical microscope.

Analysis of the formation rock samples in this embodiment shows that different typical minerals (silicate minerals, carbonate minerals, clay minerals) and organic matter have a significant impact on the interface properties of the formation rock and oil-based drilling fluid system, but the degree of influence and affect in different ways. Fig. 12 is a graph showing the relationship between the contact angle and the content of silicate minerals under the pH value of 6.5 and different demulsification voltages.

The oil-based drilling fluid components of the present embodiment are as follows, calculated in weight percent: diesel oil, water, main emulsifier (VERSAMUL) 1.6%, auxiliary emulsifier (VERSACOAT HF) 2.5%, calcium chloride 4.0%, organic soil (VG -PLUS) 0.5%, fluid loss reducer I (VERSATROL) 2.0%, fluid loss reducer II (ECOTROL RD) 0.25%, alkalinity control agent (calcium oxide) 2.8%, weighting agent (barite).

Adjust the oil-water ratio and the amount of emulsifier added to configure oil-based drilling fluids with different properties. The key parameters of oil-based drilling fluid are demulsification voltage (E), pH value, oil-water ratio (O/W), emulsifier addition amount (W _e ). The amount of emulsifier added is the amount of main emulsifier added and the amount of auxiliary emulsifier added.

Fig. 13 is a graph showing the relationship between the contact angle and the demulsification voltage of the oil-based drilling fluid at different pH values when the physical and structural properties of the formation rock are constant.

Fig. 14 is a graph showing the relationship between the demulsification voltage and pH value of the oil-based drilling fluid and the stress intensity factor when the rock physical properties and structural properties of the formation are constant.

In this implementation, the oil-based drilling fluid is used in a sandstone formation in Yunnan. The key parameter window is: the oil-water ratio is 75-85:15-25, the main emulsifier addition is 0.95-2.0%, and the auxiliary emulsifier addition is 1.4 -2.7%, PH value is 7.0-9.0, demulsification voltage is 400-940V.

It is not difficult for those skilled in the art to understand that the design method of oil-based drilling fluid parameters of the present invention includes any combination of the summary of the invention and the specific embodiments of the description of the present invention described above and the various parts shown in the accompanying drawings. The specification is concise and does not describe each scheme constituted by these combinations one by one. Any modifications, equivalent replacements, improvements, etc. made within the spirit and principles of the present invention shall be included within the protection scope of the present invention.

Claims (10)

1. a method for designing for oil base drilling fluid parameter, it comprises the following steps according to sequencing:

Step one: by physical property and the structural property of experimental test formation rock;

Step 2: according to physical property and the structural property of formation rock, set up the comprehensive characterization model of typical mineral, the pore texture of formation rock, oil base drilling fluid parameter formation rock and oil base drilling fluid system wetting state, and draw the graph of a relation between oil base drilling fluid parameter and wetting state;

Step 3: set up formation rock and the stability of wellbore by mechanics model of oil base drilling fluid system under wetting state condition, and draw the graph of a relation between oil base drilling fluid parameter and wellbore stability;

Step 4: according to the graph of a relation between oil base drilling fluid parameter and wellbore stability, determines oil base drilling fluid parameter.

2. the method for designing of oil base drilling fluid parameter as claimed in claim 1, is characterized in that: in step one, at least gets ten pieces of formation rocks, test its physical property and structural property respectively.

3. the method for designing of oil base drilling fluid parameter as claimed in claim 2, is characterized in that: the mineral constituent adopting X-ray diffraction experimental test formation rock.

4. the method for designing of oil base drilling fluid parameter as claimed in claim 2, is characterized in that: the total content of organic carbon, Kerogen type, the degree of ripeness that adopt thermal decomposition test and vitrinite reflectance experimental test formation rock.

5. the method for designing of oil base drilling fluid parameter as claimed in claim 2, is characterized in that: the distribution of pores adopting scanning electron microscope, transmission electron microscope, CT experimental test formation rock.

6. the method for designing of oil base drilling fluid parameter as claimed in claim 5, is characterized in that: the factor of porosity adopting focused ion beam test, nitrogen adsorption test formation testing rock.

7. the method for designing of oil base drilling fluid parameter as claimed in claim 2, is characterized in that: the fracture toughness adopting Brazilian diametral compression test formation testing rock.

8. the method for designing of oil base drilling fluid parameter as claimed in claim 1, it is characterized in that: in step 2, the foundation of the comprehensive characterization model of the pore texture of typical mineral, formation rock, oil base drilling fluid parameter formation rock and oil base drilling fluid system wetting state, it comprises the following steps according to sequencing:

Step one: formation rock is made ternary phase diagram according to the percentage by weight of silicate mineral, carbonate mineral, clay mineral three quasi-representative mineral, analyze the mineral constituent of having surveyed formation rock, and classify according to the drop point of mineral constituent in ternary phase diagram;

Step 2: the canonical measure surface of preparing typical mineral formation rock respectively;

Step 3: the contact angle of canonical measure surface under oil base drilling fluid effect measuring typical mineral formation rock respectively, and the test data of the total content of organic carbon of formation rock corresponding to combining respectively, Kerogen type, pore texture, analyze the impact of typical mineral, total content of organic carbon, factor of porosity formation rock and oil base drilling fluid system wetting state;

Step 4: by adjustment ow ratio and emulsifying agent addition, the oil base drilling fluid of preparation different performance, and measure its emulsion-breaking voltage, viscosity, pH value, API filter vector, HTHP filters vector;

Step 5: the contact angle of canonical measure surface under the oil base drilling fluid effect of different performance measuring typical mineral formation rock respectively, analyzes the impact of oil base drilling fluid parameter formation rock and oil base drilling fluid system wetting state;

Step 6: according to the test data of the percentage by weight of typical mineral, total content of organic carbon, factor of porosity, oil base drilling fluid parameter, contact angle, set up the comprehensive characterization model of formation rock and oil base drilling fluid system wetting state.

9. the method for designing of oil base drilling fluid parameter as claimed in claim 8, is characterized in that: analyze the mineral constituent of having surveyed formation rock, be at least quasi-representative mineral.

10. the method for designing of oil base drilling fluid parameter as claimed in claim 9, is characterized in that: analyzing the mineral constituent of having surveyed formation rock, is three quasi-representative mineral.