A high-temperature and high-density water-based drilling fluid and its preparation method

Abstract

The present invention provides a high-temperature and high-density water-based drilling fluid. The components of the water-based drilling fluid, measured by weight, include: 100 parts of water, 1.5-3 parts of bentonite, 0.2-0.3 parts of soda ash, 0.5-0.8 parts of sodium hydroxide, 0.5-2 parts of nano-anti-high-temperature fluid loss reducer, 1.5-4 parts of high-temperature emulsion viscosity enhancer, 2-3 parts of plugging agent, 1-2 parts of nano-plugging agent, 0.1-0.2 parts of deoxidizer, 1-2 parts of dispersant, 50%-100% of water-soluble organic salt and barite adapted to the required density. The drilling fluid system has good rheological properties, low viscosity and shear, strong suspension stability and salt and pollution resistance under high-temperature and high-density conditions.

Description

Technical Field

[0001] The present invention belongs to the technical field of drilling fluids, and in particular relates to a high-temperature and high-density water-based drilling fluid and a preparation method thereof. Background Art

[0002] As my country's oil and gas resource exploration advances into deep formations, high-temperature and high-pressure formations are often encountered. More and more oil and gas wells are constructed using high-temperature and high-density drilling fluids. The research and development of high-temperature and high-density drilling fluid systems with excellent performance and outstanding high-temperature sedimentation stability is of great significance for safe drilling, speed improvement and efficiency improvement in deep, high-temperature and high-pressure formations.

[0003] However, a large number of drilling practices have shown that high-density drilling fluids weighted with barite generally have problems such as difficulty in regulating rheological properties, large filtration loss at high temperature and high pressure, and sedimentation of solid-phase weighted materials under high-temperature environments. At the drilling site, high-temperature and high-density drilling fluids are prone to a vicious cycle of "weighting and thickening - treatment to reduce viscosity - sedimentation of weighted materials (causing downhole complexity and reducing the density of the drilling fluid - weighting again). Therefore, there is a contradiction between the rheology and sedimentation stability of high-temperature and high-density drilling fluids that is difficult to balance. At the same time, high-temperature aging will cause reversible and irreversible changes in components such as clay and treatment agents in the drilling fluid, thereby affecting the rheological properties and other properties of the drilling fluid at high temperature and before and after aging. In addition, high-density drilling fluids (general density > 1.03g / cm 3 ) has a very high solid content, with a density of 2.3g / cm 3 As an example of drilling fluid, barite (density 4.3g / cm 3 ) are as high as 72.6% and 38.9% by weight, respectively, resulting in a low free water content in the system. When contaminated, it is very easy to cause a sudden change in the drilling fluid properties, making it difficult to control rheology, filtration loss and sedimentation stability.

[0004] Therefore, there is an urgent need for a drilling fluid with excellent performance that can meet the requirements of high-temperature and high-pressure formation drilling under harsh conditions. Summary of the Invention

[0005] In order to solve the above problems in the prior art, the present invention proposes a high-temperature, high-density water-based drilling fluid. The drilling fluid system has good rheological properties, low viscosity and shear, strong suspension stability and salt and pollution resistance under high temperature and high density conditions.

[0006] In the first aspect, the present invention proposes a high-temperature, high-density water-based drilling fluid, whose components, in parts by weight, include: 100 parts of clean water, 1.5 to 3 parts of bentonite, 0.2 to 0.3 parts of soda ash, 0.5 to 0.8 parts of sodium hydroxide, 0.5 to 2 parts of nano-anti-high-temperature filtration reducer, 1.5 to 4 parts of anti-high-temperature emulsion viscosity enhancer, 2 to 3 parts of plugging agent, 1 to 2 parts of nano-plugging agent, 0.1 to 0.2 parts of deoxidizer, 1 to 2 parts of dispersant, 20 to 100 parts of water-soluble organic salt and 40-400 parts of barite.

[0007] The density of the high-temperature and high-density water-based drilling fluid is 1.6 to 2.6 g / cm 3 .

[0008] Generally, the density of water-based drilling fluid is greater than 1.0 g / cm 3 ;High-density drilling fluid density greater than 1.6g / cm 3 .

[0009] As a specific embodiment of the present invention, the nano-anti-high-temperature fluid loss agent comprises a hyperbranched polymer generated by the polycondensation reaction of polyethylene polyamine and methyl acrylate, and a polytannic acid grafted hyperbranched polymer formed by the reaction of tannic acid in the presence of an oxidant; the particle size of the nano-anti-high-temperature fluid loss agent is 50-100 nm;

[0010] Preferably, the molar ratio of polyethylene polyamine to methyl acrylate is 1:(2-5);

[0011] The mass ratio of the tannic acid to the hyperbranched polymer is 1:(5-8);

[0012] More preferably, the polyethylene polyamine is diethylene triamine or triethylene tetramine.

[0013] As a specific embodiment of the present invention, the high temperature resistant emulsion viscosity enhancer is a copolymer formed by inverse emulsion polymerization of methyl acrylate, 2-acrylamido-2-methylpropanesulfonic acid, vinyl pyrrolidone, and trifluoroethyl acrylate;

[0014] Preferably, the weight ratio of methyl acrylate, 2-acrylamido-2-methylpropanesulfonic acid, vinyl pyrrolidone and trifluoroethyl acrylate is (20-30):(10-20):(5-10):(1-5).

[0015] As a specific embodiment of the present invention, the water-soluble organic salt weighting agent is at least one of sodium formate, potassium formate, Weigh2 and Weigh3 produced by Beijing Peikang.

[0016] As a specific embodiment of the present invention, the plugging agent is sulfonated asphalt and / or natural asphalt.

[0017] As a specific embodiment of the present invention, the nano plugging agent is at least one of nano silicon dioxide, nano titanium dioxide, and nano silicon dioxide emulsion; and the particle size of the nano plugging agent is 10 to 100 nm.

[0018] As a specific embodiment of the present invention, the deoxidizer is sodium sulfite or sodium citrate.

[0019] As a specific embodiment of the present invention, the dispersant is a mixture of sodium hexametaphosphate and sodium tripolyphosphate. Preferably, the mass ratio of sodium hexametaphosphate to sodium tripolyphosphate is (0.5-2):1. The present invention uses sodium hexametaphosphate and sodium tripolyphosphate as dispersants. Sodium hexametaphosphate has good suspending and dispersing effects, but the pH value of a 1% sodium hexametaphosphate solution is 6.4-6.6; while sodium tripolyphosphate has a large alkaline buffering effect, with a pH value of 9.5-9.8 for a 1% sodium tripolyphosphate solution. The two act synergistically, acting as a buffer, which can maintain the pH value of the drilling fluid system within an appropriate range at high temperatures. When the drilling fluid encounters carbonate contamination, calcium intrusion, or salt water intrusion, it maintains good drilling fluid rheology. At the same time, sodium tripolyphosphate has peptizing, emulsifying, and dispersing effects, which can improve the dissolution of emulsion thickeners and promote their emulsification, and synergize with sodium hexametaphosphate to improve the dispersion and suspension of barite.

[0020] As a specific embodiment of the present invention, the density of the barite is 4.2 to 4.4 g / cm 3 The barite is mixed with different particle sizes. Preferably, the weight ratio of 300-mesh, 2000-mesh, and 5000-mesh barite is (30-60): (20-40): (10-30); the weight ratio is preferably 50:20:10. Using barite of different mesh sizes to increase weight improves the filter cake wall-forming properties and reduces fluid loss.

[0021] As a specific embodiment of the present invention, organic salts and barite are used in combination. First, a certain concentration of organic salts can improve the temperature resistance of the treatment agent. Second, the use of organic salts increases the density of the base slurry, reduces the use of barite, and reduces the solid content of the drilling fluid system, achieving the purpose of performance optimization. Third, the reduced solid content improves the fluidity of the drilling fluid, alleviating the contradiction between the rheological properties and water loss wall-forming properties of high-density drilling fluids. Fourth, organic salts can improve the inhibitory properties of the drilling fluid.

[0022] As a specific embodiment of the present invention, the preparation method of the nano high temperature resistant fluid loss additive comprises the following steps:

[0023] A: Under nitrogen atmosphere, polyethylene polyamine and methyl acrylate are reacted in a first solvent to generate an intermediate;

[0024] B: Under vacuum conditions, polymerizing the intermediate obtained in step A in a second solvent to obtain a hyperbranched polymer;

[0025] C: Tannic acid and hyperbranched polymer are reacted in a third solvent under the action of an oxidant, and the reaction is carried out through sedimentation, centrifugal separation, and drying to obtain a nano-anti-high temperature fluid loss reducer.

[0026] As a specific embodiment of the present invention, in step A, the first solvent is tetrahydrofuran; a tetrahydrofuran solution of polyethylene polyamine and a tetrahydrofuran solution of methyl acrylate are mixed and reacted, wherein the concentration of polyethylene polyamine in the tetrahydrofuran solution is 0.05 to 0.1 g / mL; the concentration of methyl acrylate in the tetrahydrofuran solution is 0.05 to 0.2 g / mL;

[0027] In the step B, the second solvent is methanol; the vacuum degree is 500 Pa, the polymerization temperature is 100-120° C., and the polymerization time is 8-10 h;

[0028] In step C, the third solvent is ethanol; the reaction temperature is 25-35° C., and the reaction time is 2-4 hours;

[0029] The oxidant is copper sulfate hydrate (CuSO4·5H2O) and hydrogen peroxide (H2O2), and the molar ratio of CuSO4·5H2O to H2O2 is (0.9-1.1):1, preferably 1:1;

[0030] The mass ratio of the oxidant to tannic acid is (0.05-0.1):1. Preferably, the oxidant is dissolved in a fourth solvent; the fourth solvent is a Tris-HCl buffer; the solubility of the oxidant in the buffer is 0.002-0.01 g / mL, and the pH value of the buffer is 7-9, preferably 8.

[0031] As a specific embodiment of the present invention, the nano-temperature-resistant fluid loss additive of the present invention contains a hyperbranched cross-linked polymer, which has stronger temperature resistance and higher stability than conventional polymers.

[0032] As a specific embodiment of the present invention, the inverse emulsion polymerization of the high temperature resistant emulsion viscosity enhancer comprises the following steps:

[0033] Ⅰ. Dissolve the emulsifiers cetyltrimethylammonium bromide (CATB) and sodium bis(2-ethylhexyl)sulfosuccinate (AOT) in a mixture of white oil and liquid paraffin, mix well, and obtain an oil phase mixture;

[0034] II. Methyl acrylate, 2-acrylamido-2-methylpropanesulfonic acid, vinyl pyrrolidone, and trifluoroethyl acrylate monomers are mixed and dissolved in water, sodium sulfite is added, and mixed uniformly to obtain an aqueous phase mixture;

[0035] III. Add the aqueous phase mixture obtained in step II dropwise to the oil phase mixture obtained in step I, remove oxygen with nitrogen, and emulsify for 30 minutes;

[0036] IV. After emulsification is completed, potassium persulfate (KPS) is added to initiate polymerization reaction to obtain high temperature resistant emulsion viscosity enhancer.

[0037] As a specific embodiment of the present invention, in step I, the mass ratio of CATB to AOT is 1:(10-5), and the amount of CATB added is 2-6 g / L relative to the total volume of the system; the mass ratio of white oil to liquid paraffin is (20-40):(50-30); and / or,

[0038] In step II, the mass ratio of the total mass of the monomer to water is 1:(2-6); the amount of sodium sulfite added is 3-5 mmol / L relative to the total volume of the aqueous phase; and the pH value of the aqueous phase mixture is adjusted to 8-10, preferably, the pH value is 9;

[0039] In the step III, the volume ratio of the oil phase to the water phase is (3-1):2;

[0040] In step IV, the molar ratio of KPS to sodium sulfite is (0.5-1.5):1, the reaction temperature is 50-80° C., and the reaction time is 3-5 h.

[0041] As a specific embodiment of the present invention, the high-temperature emulsion thickener of the present invention incorporates AMPS, a compound with strong temperature resistance and salt insensitivity, and NVP, a compound with a five-membered ring structure that increases molecular chain rigidity, effectively improving the thickener's temperature resistance. Furthermore, the introduction of fluorine-containing groups, due to the high electronegativity of fluorine, stabilizes the C-F bond, and the fluorine-containing side chains are oriented outward, effectively enhancing the polymer's temperature and salt resistance.

[0042] The inverse emulsion polymerization method is adopted, with mild synthesis conditions, simple synthesis process and fast reaction speed. The synthesized emulsion thickener has good water solubility and fast dissolution speed, which can effectively overcome the waste and performance degradation caused by the formation of "fish eyes" due to incomplete dissolution of powdered polymer particles.

[0043] In a second aspect, the present invention provides a method for preparing the high-temperature, high-density water-based drilling fluid, comprising the following steps:

[0044] S1: adding bentonite, soda ash and sodium hydroxide to clean water and mixing them evenly to obtain a first mixture;

[0045] S2: adding nano high temperature resistant fluid loss additive to the first mixture and mixing evenly to obtain a second mixture;

[0046] S3: adding a high temperature resistant emulsion viscosity enhancer to the second mixture and mixing uniformly to obtain a third mixture;

[0047] S4: adding a plugging agent, a nano plugging agent, an oxygen scavenger, a dispersant, and a water-soluble organic salt to the third mixture in sequence, and mixing them evenly to obtain a fourth mixture;

[0048] S5: adding barite of different particle size ratios to the fourth mixture, adjusting the density of the drilling fluid, and mixing uniformly to prepare a high-temperature and high-density water-based drilling fluid.

[0049] As a specific embodiment of the present invention, the step S1 further comprises curing after mixing, wherein the curing temperature is 20-30° C. and the curing time is 20-30 h.

[0050] As a specific embodiment of the present invention, in the steps S1 to S5, the mixing method is independently stirring; the stirring rate is 10,000 to 15,000 r / min; and the stirring time is 30 to 60 min.

[0051] As a specific embodiment of the present invention, the density of the high-temperature and high-density water-based drilling fluid obtained in step S5 is 1.6-2.6 g / cm 3 .

[0052] The above raw materials in the present invention can be prepared in-house or purchased commercially, and the present invention is not particularly limited thereto.

[0053] Compared with the prior art, the present invention has the following beneficial effects:

[0054] 1. The nano-anti-high-temperature fluid loss reducer of the present invention is prepared by reacting tannic acid (TA), a natural plant polyphenol compound, with a hyperbranched polymer. The resulting particles have low toxicity, are environmentally friendly, and are biodegradable. The resulting particles are rich in catechol hydroxyl groups from tannic acid and amino groups from branched polyamines, and can form multi-site, strong adhesion effects with clay molecules, providing strong connection forces to the end faces of micro-fractures in the formation, thereby sealing the pore throats of shale. The stacked structure of polytannic acid benzene rings is hydrophobic, which can prevent water molecules from entering the clay layer and reduce fluid loss. The nanoparticle structure can play a physical sealing role.

[0055] 2. The high-temperature, high-density drilling fluid of the present invention still has good rheological properties, sedimentation stability, and fluid loss and wall-building properties after hot rolling aging at 230°C. The HTHP fluid loss is low, and after 7 days of aging and standing, the sedimentation coefficient is less than 0.53. The aged slurry quickly recovers its performance after low-speed stirring.

[0056] 3. The high temperature and high density drilling fluid of the present invention has a relatively low solid content, at 2.3 g / cm 3 As an example of drilling fluid, barite (density 4.3g / cm 3 ) is adjustable within a weight percentage range of 69.5% to 55.3%, and the corresponding volume percentage is 37.2% to 29.6%. DETAILED DESCRIPTION

[0057] The present invention will be further described below with reference to specific examples, but they do not constitute any limitation to the present invention.

[0058] In each embodiment of the present invention, the specific information of the reagents used is as follows:

[0059] Diethylenetriamine, analytical grade, was purchased from Shanghai Aladdin Biochemical Technology Co., Ltd.;

[0060] Tetrahydrofuran, analytical grade, was purchased from Shanghai Aladdin Biochemical Technology Co., Ltd.;

[0061] Methyl acrylate, analytical grade, was purchased from Tianjin Chemical Reagent Research Institute;

[0062] Tris-HCl buffer was purchased from Shanghai MacLean Biochemical Technology Co., Ltd.;

[0063] Methyl acrylate, analytical grade, was purchased from Shanghai Aladdin Biochemical Technology Co., Ltd.;

[0064] 2-Acrylamido-2-methylpropanesulfonic acid, analytical grade, was purchased from Sinopharm Chemical Reagent Co., Ltd.;

[0065] Vinyl pyrrolidone, analytical grade, was purchased from Sinopharm Chemical Reagent Co., Ltd.;

[0066] Trifluoroethyl acrylate was purchased from Shanghai MacLean Biochemical Technology Co., Ltd.

[0067] Hexadecyltrimethylammonium bromide (CATB) was purchased from Sinopharm Chemical Reagent Co., Ltd.

[0068] Sodium bis(2-ethylhexyl)sulfosuccinate (AOT) was purchased from Sinopharm Chemical Reagent Co., Ltd.

[0069] Sulfonated asphalt was purchased from Shandong Deshunyuan Petroleum Technology Co., Ltd.

[0070] Nano-silica, particle size 30-100 nm, purchased from Shandong Zhongsheng Petrochemical Co., Ltd.

[0071] Sodium hexametaphosphate, analytical grade, was purchased from Sinopharm Chemical Reagent Co., Ltd.;

[0072] Sodium tripolyphosphate, analytical grade, was purchased from Shanghai Aladdin Biochemical Technology Co., Ltd.;

[0073] 300 mesh barite: density 4.3g / cm 3 , from Guangxi Jieluoxin Mining Co., Ltd.;

[0074] 2000 mesh barite: density 4.3g / cm 3 , from Guangxi Jieluoxin Mining Co., Ltd.;

[0075] 5000 mesh barite: density 4.3g / cm 3 , from Guangxi Jieluoxin Mining Co., Ltd.

[0076] Example 1

[0077] This embodiment provides a high-temperature, high-density water-based drilling fluid and a preparation method thereof. The specific details are as follows:

[0078] (1) Preparation of nano high temperature resistant fluid loss additive:

[0079] A: Place a mixed solution of 2.58g diethylenetriamine and 50mL tetrahydrofuran in a reaction vessel. Dissolve 4.30g methyl acrylate in 50mL tetrahydrofuran and place in a constant pressure dropping funnel. Cool the reaction vessel to 5°C in an ice-water bath. Purge nitrogen and add the methyl acrylate-containing tetrahydrofuran solution dropwise to the reaction vessel over a 0.5h period. After the addition is complete, raise the temperature to 30°C and react for 5h to produce an intermediate. Place the intermediate on a rotary evaporator set to a reduced vacuum of 500Pa and dry at 40°C for 4h to remove unreacted monomer and other solvents.

[0080] B: 5.0 g of the intermediate obtained in step A was dissolved in 50 mL of methanol in a reactor, and the reduced vacuum was set to 500 Pa. The polymerization reaction was carried out under a rotary motion at 100° C. for 8 h, and then cooled to 30° C. to obtain a hyperbranched polymer.

[0081] C: 0.5 g of tannic acid and 2.5 g of the hyperbranched polymer obtained in step B were separately dissolved in 50 mL of ethanol to obtain a tannic acid solution and a hyperbranched polymer solution; 0.025 g of an oxidant was prepared by mixing copper sulfate hydrate (CuSO4·5H2O) and hydrogen peroxide (H2O2) in a molar ratio of 1:1 and dissolved in 10 mL of Tris-HCl buffer at a pH of 8 to obtain an oxidant solution; the prepared tannic acid solution and hyperbranched polymer solution were mixed, the oxidant solution was added, stirred, reacted at 30°C for 2 h, allowed to settle overnight, centrifuged, and dried to obtain a nano-high-temperature resistant fluid loss reducer.

[0082] (2) High temperature resistant emulsion viscosity increaser:

[0083] I: Dissolve 0.158 g of CATB and 0.79 g of AOT in a mixture of 20 g of white oil and 50 g of liquid paraffin, and stir uniformly with ultrasonication to obtain an oil phase mixture.

[0084] II: 10 g of methyl acrylate, 10 g of 2-acrylamido-2-methylpropanesulfonic acid, 4.5 g of vinyl pyrrolidone, and 0.5 g of trifluoroethyl acrylate were dissolved in 100 g of distilled water. The pH value of the system was adjusted to 9. 0.3 mmol of sodium sulfite was added and ultrasonically stirred to obtain an aqueous phase mixture.

[0085] III: Add the aqueous phase mixture dropwise to the oil phase mixture at a volume ratio of 2:2, stirring while adding, and pass nitrogen to deoxygenate, and emulsify for 30 minutes;

[0086] IV: After emulsification is completed, 0.225 mmol KPS is added to initiate polymerization reaction at a reaction temperature of 50°C for 5 h to obtain a high temperature resistant emulsion viscosity enhancer.

[0087] (3) Preparation of high-temperature and high-density water-based drilling fluid:

[0088] S1: adding 1.5 parts by weight of bentonite, 0.2 parts by weight of soda ash, and 0.5 parts by weight of sodium hydroxide to 100 parts by weight of clean water at a rotation speed of 11,000 r / min while stirring, stirring for 30 minutes, and then curing at 25° C. for 24 hours to obtain a first mixture;

[0089] S2: adding 0.5 parts by weight of the nanometer high-temperature resistant fluid loss additive prepared in step (1) to the first mixture, and stirring at a speed of 11,000 rpm for 30 minutes to obtain a second mixture;

[0090] S3: adding 4 parts by weight of the high-temperature resistant emulsion viscosity enhancer from step (2) to the second mixture, and stirring at a speed of 11,000 rpm for 30 minutes to obtain a third mixture;

[0091] S4: adding 3 parts by weight of sulfonated asphalt, 1 part by weight of nano-silica, 0.1 part by weight of sodium sulfite, 1 part by weight of a dispersant (wherein the mass ratio of sodium hexametaphosphate to sodium tripolyphosphate is 0.5:1), 20 parts of sodium formate, and 30 parts of potassium formate to the third mixture in sequence, and stirring at a speed of 11,000 r / min for 50 minutes to obtain a fourth mixture;

[0092] S5: Add 294.6 parts of barite to the fourth mixture, where the mass ratio of 300 mesh barite, 2000 mesh barite and 5000 mesh barite is 50:20:10, and adjust the drilling fluid density to 2.3 g / cm 3, and stirred at a speed of 11000r / min for 60min to obtain a high-temperature and high-density water-based drilling fluid.

[0093] The weight percentage of barite in the high-temperature, high-density water-based drilling fluid of Example 1 is 66.0% and the volume percentage is 35.3%.

[0094] Example 2

[0095] This embodiment provides a high-temperature, high-density water-based drilling fluid and a preparation method thereof. The specific details are as follows:

[0096] (1) Nano high temperature resistant fluid loss reducer

[0097] A: Place a mixed solution of 2.58g diethylenetriamine and 50mL tetrahydrofuran in a reaction vessel. Dissolve 10.76g methyl acrylate in 100mL tetrahydrofuran and place in a constant pressure dropping funnel. Cool the reaction vessel to 5°C in an ice-water bath. Purge nitrogen and add the tetrahydrofuran solution containing methyl acrylate dropwise to the reaction vessel over a 1h period. After the addition is complete, raise the temperature to 30°C and react for 6h to produce an intermediate. Place the intermediate on a rotary evaporator, set the vacuum to 500Pa, and dry at 40°C for 6h to remove unreacted monomer and other solvents.

[0098] B: 5.0 g of the intermediate obtained in step A was dissolved in 50 mL of methanol in a reactor, and the reduced vacuum was set to 500 Pa. The polymerization reaction was carried out at 120° C. for 10 h, and then cooled to 30° C. to obtain a hyperbranched polymer.

[0099] C: 0.5 g of tannic acid and 4.0 g of the hyperbranched polymer obtained in step B were separately dissolved in 50 mL of ethanol to obtain a tannic acid solution and a hyperbranched polymer solution; 0.05 g of an oxidant was prepared by mixing copper sulfate hydrate (CuSO4·5H2O) and hydrogen peroxide (H2O2) at a molar ratio of 0.9:1 and dissolved in 10 mL of Tris-HCl buffer (pH 8) to obtain an oxidant solution; the prepared tannic acid solution and hyperbranched polymer solution were mixed, the oxidant solution was added, stirred, reacted at 30°C for 4 h, allowed to settle overnight, centrifuged, and dried to obtain a nano-high-temperature resistant fluid loss reducer.

[0100] (2) High temperature resistant emulsion viscosity increaser:

[0101] I: Dissolve 0.316 g of CATB and 2.212 g of AOT in a mixture of 30 g of white oil and 40 g of liquid paraffin, and stir uniformly with ultrasonication to obtain an oil phase mixture.

[0102] II: 12.5 g of methyl acrylate, 7.5 g of 2-acrylamido-2-methylpropanesulfonic acid, 3.5 g of vinyl pyrrolidone, and 1.5 g of trifluoroethyl acrylate were dissolved in 100 g of distilled water. The pH value of the system was adjusted to 9. 0.4 mmol of sodium sulfite was added and ultrasonically stirred to obtain an aqueous phase mixture.

[0103] III: Add the aqueous phase mixture dropwise to the oil phase mixture at a volume ratio of 1:2, stirring while adding dropwise, and pass nitrogen to deoxygenate, and emulsify for 30 minutes;

[0104] IV: After emulsification is completed, 0.2 mmol KPS is added to initiate polymerization reaction, the reaction temperature is 60 ° C, the reaction time is 4 h, and the high temperature resistant emulsion viscosity enhancer is obtained.

[0105] (3) Preparation of high-temperature and high-density water-based drilling fluid:

[0106] S1: adding 2 parts by weight of bentonite, 0.3 parts by weight of soda ash, and 0.6 parts by weight of sodium hydroxide to 100 parts by weight of clean water at a rotation speed of 11,000 r / min while stirring, stirring for 30 minutes, and then curing at 25° C. for 24 hours to obtain a first mixture;

[0107] S2: adding 1 part by weight of the nanometer high-temperature resistant fluid loss additive prepared in step (1) to the first mixture, and stirring at a speed of 11,000 r / min for 30 minutes to obtain a second mixture;

[0108] S3: adding 2 parts by weight of the high-temperature resistant emulsion viscosity enhancer from step (2) to the second mixture, and stirring at a speed of 11,000 rpm for 30 minutes to obtain a third mixture;

[0109] S4: adding 2 parts by weight of natural asphalt, 1.5 parts by weight of nano-titanium dioxide, 0.15 parts by weight of sodium citrate, 1.5 parts by weight of a dispersant (wherein the mass ratio of sodium hexametaphosphate to sodium tripolyphosphate is 1:1), 50 parts of weigh 2, and 50 parts of weigh 3 to the third mixture in sequence, and stirring at a speed of 11,000 rpm for 50 minutes to obtain a fourth mixture;

[0110] S5: Add 277 parts of barite to the fourth mixture, where the mass ratio of 300 mesh barite, 2000 mesh barite and 5000 mesh barite is 50:40:20, and adjust the drilling fluid density to 2.3 g / cm 3 , and stirred at a speed of 11000r / min for 60min to obtain a high-temperature and high-density water-based drilling fluid.

[0111] The weight percentage of barite in the high-temperature, high-density water-based drilling fluid of Example 2 is 57.6% and the volume percentage is 30.3%.

[0112] Example 3

[0113] This embodiment provides a high-temperature, high-density water-based drilling fluid and a preparation method thereof. The specific details are as follows:

[0114] (1) Nano high temperature resistant fluid loss reducer

[0115] A: Place a mixed solution of 7.30 g of triethylenetetramine and 100 mL of tetrahydrofuran in a reaction vessel. Dissolve 12.91 g of methyl acrylate in 100 mL of tetrahydrofuran and place in a constant pressure dropping funnel. Cool the reaction vessel to 5°C in an ice-water bath. Purge nitrogen and add the methyl acrylate-containing tetrahydrofuran solution dropwise over a 0.8 hour period. After the addition is complete, continue the reaction at 30°C for 5 hours to produce an intermediate. Place the intermediate on a rotary evaporator at a reduced vacuum of 500 Pa and dry at 40°C for 5 hours to remove unreacted monomer and other solvents.

[0116] B: 5.0 g of the intermediate obtained in step A was dissolved in 50 mL of methanol in a reactor. The reduced vacuum was set to 500 Pa. The polymerization reaction was carried out under a rotary motion at 110° C. for 9 h. The reaction was then cooled to 30° C. to obtain a hyperbranched polymer.

[0117] C: 0.5 g of tannic acid and 3.0 g of the hyperbranched polymer obtained in step B were separately dissolved in 50 mL of ethanol; 0.03 g of an oxidant was prepared by mixing copper sulfate hydrate (CuSO4·5H2O) and hydrogen peroxide (H2O2) at a molar ratio of 1.1:1 and dissolved in 10 mL of Tris-HCl buffer, the pH of the buffer being 8; the prepared tannic acid solution and hyperbranched polymer solution were mixed, the oxidant solution was added, stirred, and reacted at 30°C for 3 h. The mixture was allowed to settle overnight, centrifuged, and dried to obtain a nano-high-temperature resistant fluid loss reducer.

[0118] (2) High temperature resistant emulsion viscosity increaser

[0119] I: Dissolve 0.48 g of CATB and 4.8 g of AOT in a mixture of 40 g of white oil and 30 g of liquid paraffin, and stir the mixture by ultrasonication to obtain an oil phase mixture.

[0120] II: 15 g of methyl acrylate, 5 g of 2-acrylamido-2-methylpropanesulfonic acid, 2.5 g of vinyl pyrrolidone, and 2.5 g of trifluoroethyl acrylate were dissolved in 100 g of distilled water. The pH value of the system was adjusted to 9. 0.5 mmol of sodium sulfite was added and ultrasonically stirred to obtain an aqueous phase mixture.

[0121] III: Add the aqueous phase mixture dropwise to the oil phase mixture at a volume ratio of 3:2, stirring while adding dropwise, and pass nitrogen to deoxygenate, and emulsify for 30 minutes;

[0122] IV: After emulsification is completed, 0.25 mmol KPS is added to initiate polymerization reaction at a reaction temperature of 70°C for 3 h to obtain a high temperature resistant emulsion viscosity enhancer.

[0123] (3) Preparation of high-temperature and high-density water-based drilling fluid

[0124] S1: adding 3 parts by weight of bentonite, 0.3 parts by weight of soda ash, and 0.8 parts by weight of sodium hydroxide to 100 parts by weight of clean water at a rotation speed of 11,000 r / min while stirring, stirring for 30 minutes, and then curing at 25° C. for 24 hours to obtain a first mixture;

[0125] S2: adding 2 parts by weight of the nanometer high temperature resistant fluid loss additive obtained in step (1) to the first mixture, and stirring at a speed of 11000 r / min for 30 minutes to obtain a second mixture;

[0126] S3: adding 1.5 parts by weight of the high-temperature resistant emulsion viscosity enhancer obtained in step (2) to the second mixture, and stirring at a speed of 11,000 rpm for 30 minutes to obtain a third mixture;

[0127] S4: adding 2 parts by weight of sulfonated asphalt, 2 parts by weight of nano-silica, 0.2 parts by weight of sodium sulfite, 2 parts by weight of a dispersant (wherein the mass ratio of sodium hexametaphosphate to sodium tripolyphosphate is 2:1), and 100 parts of weigh3 to the third mixture in sequence, and stirring at a speed of 11,000 rpm for 50 minutes to obtain a fourth mixture;

[0128] S5: Add 251.2 parts of barite to the fourth mixture, where the mass ratio of 300 mesh barite, 2000 mesh barite and 5000 mesh barite is 60:20:20, and adjust the drilling fluid density to 2.3 g / cm 3 , and stirred at a speed of 11000r / min for 60min to obtain a high-temperature and high-density water-based drilling fluid.

[0129] The weight percentage of barite in the high-temperature, high-density water-based drilling fluid of Example 3 is 55.3% and the volume percentage is 29.6%.

[0130] Comparative Example 1

[0131] The difference from Example 3 is that in the third part of the preparation step: step S4 in the process of preparing the high-temperature and high-density water-based drilling fluid, 20 parts of sodium formate and 30 parts of potassium formate are not added.

[0132] Comparative Example 2

[0133] The difference from Example 3 is that in the preparation step part (iii): in step S2 of the process of preparing high-temperature and high-density water-based drilling fluid, 2 parts by weight of nano-anti-high-temperature fluid loss reducer are replaced by 2 parts by weight of phenolic resin SMP-3, purchased from Shandong Deshunyuan Petroleum Technology Co., Ltd.

[0134] Comparative Example 3

[0135] The difference from Example 3 is that in the preparation step part (iii): in step S3 of the process of preparing high-temperature and high-density water-based drilling fluid, 1.5 parts by weight of the high-temperature resistant emulsion viscosity enhancer is replaced by 1.5 parts by weight of sulfonate copolymer DSP-1, which is purchased from Shandong Deshunyuan Petroleum Technology Co., Ltd.

[0136] Test Example 1

[0137] Referring to GB16783.1-2014 "Field Test of Drilling Fluids in the Petroleum and Natural Gas Industry Part 1: Water-Based Drilling Fluids", the high-temperature, high-density water-based drilling fluids prepared in Examples 1 to 3 and Comparative Examples 1-3 were heated at 230°C for 16 hours and then cooled to 50°C for performance testing. The results are shown in Table 1 below.

[0138] Table 1 Performance of the embodiment before and after aging

[0139]

[0140] Note: FL HTHP Measured at 180°C and 3.5 MPa.

[0141] As can be seen from the test results of Table 1, the high-temperature resistant high-density water-based drilling fluids prepared in Examples 1 to 3 have good high-temperature stability and rheological stability. After aging at 230°C, the rheological properties change little, and the high-temperature and high-pressure fluid loss is also controlled to be below 15mL. Compared with Comparative Example 3, Example 3 shows a significant reduction in apparent viscosity, plastic viscosity, and dynamic shear force, which provides room for improvement in the performance of the drilling fluid in the later stage. Compared with Comparative Examples 2-3, the nano-anti-high-temperature fluid loss agent of the present invention has a better viscosity-increasing and fluid loss-reducing effect than the phenolic resin SMP-3, and the high-temperature resistant emulsion viscosity-increasing agent of the present invention has a better viscosity-increasing and temperature resistance than the sulfonate copolymer DSP-1.

[0142] Test Example 2

[0143] Sedimentation stability test method: After the high-temperature, high-density water-based drilling fluids prepared in Examples 1 to 3 and Comparative Examples 1 to 3 were heated at 230°C for a certain period of time, the density of the upper and lower layers of drilling fluid was measured. According to formula (1), the sedimentation stability coefficient SF value was calculated, as shown in Table 2.

[0144] Sedimentation stability coefficient SF = ρ 下 / (ρ 上 +ρ 下 ) Formula (1)

[0145] Table 2: Sedimentation stability coefficient SF under high temperature in the embodiment

[0146]

[0147] As shown in Table 2, the sedimentation stability of Examples 1-3 is relatively strong, and the sedimentation stability coefficient after 7 days is less than 0.53, which can meet the requirements of high temperature and high pressure formation drilling. In comparison, the sedimentation stability of Comparative Examples 1-3 is slightly poor.

[0148] In summary, the high-temperature, high-density drilling fluid of the present invention still has good rheological properties, sedimentation stability and fluid loss and wall-building properties after hot rolling aging at 230°C. The HTHP fluid loss is low. After 7 days of aging and standing, the sedimentation coefficient is less than 0.53. The aged slurry quickly recovers its performance after low-speed stirring.

[0149] Any numerical value mentioned in this invention includes all values ​​from the lowest value to the highest value in increments of one unit if there is only a two-unit interval between any minimum value and any maximum value. For example, if the amount of a component, or a process variable such as temperature, pressure, or time, is stated to be 50-90, it is intended in this specification that values ​​such as 51-89, 52-88, ..., 69-71, and 70-71 are specifically listed. For non-integer values, units of 0.1, 0.01, 0.001, or 0.0001 may be appropriately considered. These are just some examples of specific indications. In this application, in a similar manner, all possible combinations of numerical values ​​between the lowest and highest values ​​listed are considered to be disclosed.

[0150] It should be noted that the embodiments described above are only used to explain the present invention and do not constitute any limitation of the present invention. The present invention has been described with reference to typical embodiments, but it should be understood that the words used therein are descriptive and explanatory words, rather than restrictive words. The present invention may be modified as specified within the scope of the claims of the present invention, and the present invention may be revised without departing from the scope and spirit of the present invention. Although the present invention described therein relates to specific methods, materials and embodiments, it does not mean that the present invention is limited to the specific examples disclosed therein. On the contrary, the present invention can be extended to all other methods and applications with the same function.

Claims

1. A high-temperature, high-density water-based drilling fluid, characterized in that: The components include, in parts by weight: 100 parts of water, 1.5-3 parts of bentonite, 0.2-0.3 parts of soda ash, 0.5-0.8 parts of sodium hydroxide, 0.5-2 parts of nano-anti-high temperature fluid loss reducer, 1.5-4 parts of anti-high temperature emulsion viscosity enhancer, 2-3 parts of plugging agent, 1-2 parts of nano-plugging agent, 0.1-0.2 parts of deoxidizer, 1-2 parts of dispersant, 20-100 parts of water-soluble organic salt and 40-400 parts of barite; The nano-anti-high-temperature fluid loss reducer comprises a polytannic acid grafted hyperbranched polymer formed by the reaction of a hyperbranched polymer generated by the polycondensation reaction of polyethylene polyamine and methyl acrylate with tannic acid under the action of an oxidant; the molar ratio of the polyethylene polyamine to methyl acrylate is 1:(2-5); the mass ratio of the tannic acid to the hyperbranched polymer is 1:(5-8); The high temperature resistant emulsion viscosity enhancer is a copolymer formed by inverse emulsion polymerization of methyl acrylate, 2-acrylamido-2-methylpropanesulfonic acid, vinyl pyrrolidone, and trifluoroethyl acrylate; the weight ratio of the methyl acrylate, 2-acrylamido-2-methylpropanesulfonic acid, vinyl pyrrolidone, and trifluoroethyl acrylate is (20-30): (10-20): (5-10): (1-5); The density of the high-temperature and high-density water-based drilling fluid is 1.6-2.6 g / cm 3 .

2. The high-temperature, high-density water-based drilling fluid according to claim 1, characterized in that: The particle size of the nano high temperature resistant fluid loss reducer is 50-100 nm.

3. The high-temperature, high-density water-based drilling fluid according to claim 1, characterized in that: The polyethylene polyamine is diethylenetriamine or triethylenetetramine.

4. The high-temperature, high-density water-based drilling fluid according to any one of claims 1 to 3, characterized in that: The water-soluble organic salt weighting agent is at least one of sodium formate, potassium formate, Weigh2 and Weigh3 produced by Beijing Peikang.

5. The high-temperature, high-density water-based drilling fluid according to any one of claims 1 to 3, characterized in that: The plugging agent is sulfonated asphalt and / or natural asphalt; and / or, The nano-blocking agent is at least one of nano-silicon dioxide, nano-titanium dioxide, and nano-silicon dioxide emulsion; the particle size of the nano-blocking agent is 10-100 nm; and / or, The deoxidizer is sodium sulfite or sodium citrate; and / or, The dispersant is a mixture of sodium hexametaphosphate and sodium tripolyphosphate; and / or, The density of the barite is 4.2-4.4 g / cm 3 .

6. The high-temperature, high-density water-based drilling fluid according to claim 5, characterized in that: The mass ratio of sodium hexametaphosphate to sodium tripolyphosphate is (0.5-2):

1.

7. The high-temperature, high-density water-based drilling fluid according to claim 5, characterized in that: The barite is compounded with different particle sizes.

8. The high-temperature, high-density water-based drilling fluid according to claim 7, characterized in that: The barite is a compound of 300 mesh, 2000 mesh and 5000 mesh.

9. The high-temperature, high-density water-based drilling fluid according to claim 8, characterized in that: The weight ratio of 300 mesh, 2000 mesh and 5000 mesh barite is (30~60): (20~40): (10~30).

10. The high-temperature, high-density water-based drilling fluid according to claim 9, characterized in that: The weight ratio of 300 mesh, 2000 mesh and 5000 mesh barite is 50:20:

10.

11. The high-temperature, high-density water-based drilling fluid according to any one of claims 1 to 3, characterized in that: The preparation method of the nano high temperature resistant fluid loss additive comprises the following steps: A: Under nitrogen atmosphere, polyethylene polyamine and methyl acrylate are reacted in a first solvent to generate an intermediate; B: Under vacuum conditions, polymerizing the intermediate obtained in step A in a second solvent to obtain a hyperbranched polymer; C: reacting tannic acid and hyperbranched polymer in a third solvent under the action of an oxidant, followed by sedimentation, centrifugal separation, and drying to obtain a nanometer high-temperature resistant fluid loss reducer.

12. The high-temperature, high-density water-based drilling fluid according to claim 11, characterized in that: The first solvent is tetrahydrofuran; in the step A, a tetrahydrofuran solution of polyethylene polyamine and a tetrahydrofuran solution of methyl acrylate are mixed for reaction, wherein the concentration of polyethylene polyamine in the tetrahydrofuran solution is 0.05 to 0.1 g / mL; the concentration of methyl acrylate in the tetrahydrofuran solution is 0.05 to 0.2 g / mL; and / or, In the step B, the second solvent is methanol; the vacuum degree is 300-800 Pa; the polymerization temperature is 100-120° C., and the polymerization time is 8-10 h; and / or, In step C, the third solvent is ethanol; the reaction temperature is 25-35° C., and the reaction time is 2-4 hours; and / or, The oxidant is CuSO4•5H2O and hydrogen peroxide (H2O2), and the molar ratio of CuSO4•5H2O to H2O2 is (0.9-1.1):1; and / or, The mass ratio of the oxidant to tannic acid is (0.05-0.1):

1.

13. The high-temperature, high-density water-based drilling fluid according to claim 12, characterized in that: In the step B, the vacuum degree is 500 Pa; and / or, The molar ratio of CuSO4•5H2O to H2O2 is 1:1; and / or, The oxidant is dissolved in a fourth solvent; the fourth solvent is a Tris-HCl buffer; the solubility of the oxidant in the buffer is 0.002-0.01 g / mL, and the pH value of the buffer is 7-9.

14. The high-temperature, high-density water-based drilling fluid according to claim 13, characterized in that: The pH value of the buffer solution is 8.

15. The high-temperature, high-density water-based drilling fluid according to any one of claims 1 to 3, characterized in that: The preparation method of the high temperature resistant emulsion viscosity increasing agent comprises the following steps: Ⅰ. Dissolve the emulsifiers cetyltrimethylammonium bromide (CATB) and sodium bis(2-ethylhexyl) sulfosuccinate (AOT) in a mixture of white oil and liquid paraffin, mix well, and obtain an oil phase mixture; II. Methyl acrylate, 2-acrylamido-2-methylpropanesulfonic acid, vinyl pyrrolidone, and trifluoroethyl acrylate monomers are mixed and dissolved in water, sodium sulfite is added, and mixed uniformly to obtain an aqueous phase mixture; III. Add the aqueous phase mixture obtained in step II dropwise to the oil phase mixture obtained in step I, remove oxygen with nitrogen, and emulsify for 30 minutes; IV. After emulsification is completed, potassium persulfate (KPS) is added to initiate polymerization reaction to obtain high temperature resistant emulsion viscosity enhancer.

16. The high-temperature, high-density water-based drilling fluid according to claim 15, characterized in that: In the step I, the mass ratio of CATB to AOT is 1:(10-5), and the amount of CATB added is 2-6 g / L relative to the total volume of the system; the mass ratio of white oil to liquid paraffin is (20-40):(50-30); and / or, In step II, the mass ratio of the total mass of the monomer to water is 1:(2-6); the amount of sodium sulfite added is 3-5 mmol / L relative to the total volume of the aqueous phase; the pH value of the aqueous phase mixture is adjusted to 8-10; and / or, In the step III, the volume ratio of the oil phase to the water phase is (3-1):2; and / or, In step IV, the molar ratio of KPS to sodium sulfite is (0.5-1.5):1, the reaction temperature is 50-80°C, and the reaction time is 3-5 hours.

17. The high-temperature, high-density water-based drilling fluid according to claim 16, characterized in that: The pH of the aqueous mixture was adjusted to 9.

18. A method for preparing the high-temperature, high-density water-based drilling fluid according to any one of claims 1 to 17, characterized in that: The following steps are involved: S1: adding bentonite, soda ash and sodium hydroxide to clean water and mixing them evenly to obtain a first mixture; S2: adding nano high temperature resistant fluid loss additive to the first mixture and mixing evenly to obtain a second mixture; S3: adding a high temperature resistant emulsion viscosity enhancer to the second mixture and mixing uniformly to obtain a third mixture; S4: adding a plugging agent, a nano plugging agent, an oxygen scavenger, a dispersant, and a water-soluble organic salt to the third mixture in sequence, and mixing them evenly to obtain a fourth mixture; S5: adding barite to the fourth mixture and mixing uniformly to prepare a high-temperature and high-density water-based drilling fluid.

19. The preparation method according to claim 18, characterized in that The step S1 further includes curing after mixing, wherein the curing temperature is 20-30° C. and the curing time is 20-30 h; and / or, In the steps S1 to S5, the mixing method is independently stirring; the stirring rate is 10000 to 15000 r / min; the stirring time is 30 to 60 min; and / or, The high-temperature and high-density water-based drilling fluid obtained in step S5 has a density of 1.6-2.6 g / cm 3 .

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