CN111378421A - Well killing fluid and preparation method thereof - Google Patents
Well killing fluid and preparation method thereof Download PDFInfo
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- CN111378421A CN111378421A CN201811622686.2A CN201811622686A CN111378421A CN 111378421 A CN111378421 A CN 111378421A CN 201811622686 A CN201811622686 A CN 201811622686A CN 111378421 A CN111378421 A CN 111378421A
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/504—Compositions based on water or polar solvents
- C09K8/5045—Compositions based on water or polar solvents containing inorganic compounds
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/504—Compositions based on water or polar solvents
- C09K8/506—Compositions based on water or polar solvents containing organic compounds
- C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
- C09K2208/32—Anticorrosion additives
Abstract
The invention discloses a well killing fluid and a preparation method thereof, belonging to the technical field of oil field well repairing. The well killing fluid comprises the following components in percentage by mass: 61.6 to 87.1 percent of brine, 1 to 2 percent of alkaline scale inhibitor, 0.5 to 1.0 percent of oil-soluble temporary plugging agent, 4 to 7 percent of modified attapulgite, 7 to 30 percent of calcium carbonate, 0.2 to 0.5 percent of wetting agent and the balance of defoaming agent. The density of the brine is 1.35-1.43 g/cm3And the brine comprises calcium ions with the concentration of 14-19 g/L. The density of the alkaline scale inhibitor is 1.40g/cm3The hydrogen ion concentration index is 13-14. The modified attapulgite is attapulgite subjected to ultrasonic cavitation treatment. The well killing fluid has the effects of high temperature resistance, high density, low corrosion, scale dissolution and inhibition, temporary plugging, easiness in preparation, convenience in operation and low cost by adding brine, an alkaline scale inhibitor and modified attapulgite and matching with other components, and the safety in the well killing operation process is improved. And after the well killing fluid is adopted for operation, the recovery rate of the oil-gas well yield is over 90 percent, and meanwhile, the well killing fluid is automatically released and flowback along with the operation negative pressure.
Description
Technical Field
The invention relates to a well killing fluid and a preparation method thereof, belonging to the technical field of oil field well repair.
Background
In the process of oil field production and development, in order to ensure the normal production of oil and gas wells, the oil and gas wells need to be repaired. In well servicing operations, to balance the fluid pressure in the formation and ensure the safety of the well servicing operation, the density is usually set to 1.5g/cm3The above fluid is used as a well control fluid, and a well control operation is performed using the well control fluid.
At present, the density is usually 1.4g/cm3The well killing fluid is a sodium formate system well killing fluid, and comprises the following components in percentage by mass: 37.40 to 44.21 percent of sodium formate, 2.56 to 3.46 percent of attapulgite, 0.1 to 1 percent of regulator 1#, 0.08 to 0.4 percent of regulator 2#, and the balance of tap water.
In the process of preparing the well killing fluid of the sodium formate system, the sodium formate is solid, so the sodium formate solid needs to be dissolved firstly to prepare a sodium formate solution, but in the process of preparing the sodium formate solution, after the sodium formate solid is added into water, the volume of the water can be increased, but the volume increase amount is difficult to control and the operation is difficult, so that the density of the finally prepared well killing fluid is greatly different from the density of the required well killing fluid, the well killing operation is influenced, and potential safety hazards exist. In addition, the sodium formate solution has a density of up to 1.35g/cm3The density of the prepared well killing fluid of the sodium formate system is 1.55g/cm at most3And the well killing fluid with higher density cannot be prepared. And, the cost of sodium formateHigher, increasing the cost of kill job.
Disclosure of Invention
The embodiment of the invention provides a well killing fluid and a preparation method thereof, which can solve the technical problems. The specific technical scheme is as follows:
in a first aspect, an embodiment of the present invention provides a well killing fluid, which includes the following components in percentage by mass:
61.6 to 87.1 percent of brine, 1 to 2 percent of alkaline scale inhibitor, 0.5 to 1.0 percent of oil-soluble temporary plugging agent, 4 to 7 percent of modified attapulgite, 7 to 30 percent of calcium carbonate, 0.2 to 0.5 percent of wetting agent and the balance of defoaming agent;
the density of the brine is 1.35-1.43 g/cm3The brine comprises calcium ions with the concentration of 14-19 g/L;
the density of the alkaline scale inhibitor is 1.40g/cm3The hydrogen ion concentration index is 13-14;
the modified attapulgite is attapulgite subjected to ultrasonic cavitation treatment.
In one possible implementation, the basic scale inhibitor is an organic amine polymer scale inhibitor.
In one possible implementation, the oil-soluble temporary plugging agent is oxidized asphalt powder.
In a possible implementation manner, the oil solubility of the oxidized asphalt powder is 56-73%, and the particle size ranges from 20 meshes to 280 meshes.
In one possible implementation mode, the particle size of the modified attapulgite is 200-600 meshes.
In one possible implementation manner, the particle size of the calcium carbonate ranges from 80 to 320 meshes.
In one possible implementation, the calcium carbonate has an acid solubility of 95%.
In one possible implementation, the defoamer is at least one of tributyl phosphate and white oil.
In one possible implementation mode, the wetting agent is a mixture of methanol and ethylene glycol monobutyl ether, and the volume ratio of the methanol to the ethylene glycol monobutyl ether is 23-29: 17-23.
In a second aspect, embodiments of the present invention provide a method for preparing a well control fluid, the method comprising:
adding the brine into a stirring tank according to the mass percentage of each component;
adding an alkaline scale inhibitor into the stirring tank, and uniformly stirring;
adding modified attapulgite into the stirring tank, and uniformly stirring;
adding a defoaming agent into the stirring tank, and uniformly stirring;
adding a wetting agent into the stirring tank, and uniformly stirring;
and adding calcium carbonate and an oil-soluble temporary plugging agent into the stirring tank, and uniformly stirring to obtain the well killing fluid.
The technical scheme provided by the embodiment of the invention has the following beneficial effects:
the control fluid provided by the embodiment of the invention can accurately control the volume increase of the control fluid by adding brine, and is convenient for preparing the control fluid with accurate density. By adding the alkaline scale inhibitor and cooperating with other components, the method has the functions of inhibiting the brine from invading a reservoir and reacting with bicarbonate radicals in formation water to generate precipitates in the operation process, automatically adjusting the pH value of the brine, reducing the corrosion rate of the brine and avoiding the brine from corroding underground tools in the operation process. Through adding the modified attapulgite and cooperating with other components, the space active sites of the modified attapulgite can be increased, and a suspension network structure with stable adsorptivity is formed, so that the modified attapulgite is uniformly dispersed in brine. Through adding oil-soluble temporary plugging agent, defoaming agent, wetting agent, calcium carbonate to with other component mating reaction, make this kill fluid be difficult for the seepage to get into the hydrocarbon reservoir, thereby avoid causing the injury to the hydrocarbon reservoir, and be difficult for appearing the sediment, do not have the bubble, do benefit to the pump and annotate to the operation position. After the well killing fluid is adopted for operation, the recovery rate of the oil well yield is over 90 percent, and meanwhile, the well killing fluid is automatically released and flowback along with the operation negative pressure.
Detailed Description
In order to make the technical solutions and advantages of the present invention clearer, the following describes embodiments of the present invention in further detail.
In a first aspect, an embodiment of the present invention provides a well killing fluid, which includes the following components by mass: 61.6 to 87.1 percent of brine, 1 to 2 percent of alkaline scale inhibitor, 0.5 to 1.0 percent of oil-soluble temporary plugging agent, 4 to 7 percent of modified attapulgite, 7 to 30 percent of calcium carbonate, 0.2 to 0.5 percent of wetting agent and the balance of defoaming agent;
the density of the brine is 1.35-1.43 g/cm3The brine comprises calcium ions with the concentration of 14-19 g/L;
the density of the alkaline scale inhibitor is 1.40g/cm3The hydrogen ion concentration index is 13-14;
the modified attapulgite is attapulgite subjected to ultrasonic cavitation treatment.
The brine adopted by the well killing fluid is calcium brine, the well killing fluid is liquid, and the solid does not need to be dissolved into water firstly, so that the volume increment of the well killing fluid can be accurately controlled in the process of preparing the well killing fluid, and the well killing fluid with a certain volume and accurate density is prepared.
It should be noted that sodium formate itself is a solid, and needs to be first prepared into a solution, and the volume increase amount is accurately calculated. And the prepared sodium formate system well killing fluid is inaccurate in density due to the fact that the well killing fluid is easily influenced by temperature in the preparation process. In addition, the density of sodium formate is up to 1.35g/cm3The prepared well killing fluid of the sodium formate system has the highest density of 1.55g/cm3. The density of the well killing fluid prepared by the embodiment of the invention can reach 1.60g/cm at most3Therefore, compared with the well control fluid of a sodium formate system, the well control fluid provided by the embodiment of the invention has higher density, and the application range of the well control fluid is expanded. The cost of the brine is 472.5-1120 yuan/ton, while the price of sodium formate is 3300 yuan/ton and the price of potassium formate is 10000 yuan/ton at present. Therefore, compared with a formate system, the cost for preparing the well control fluid can be greatly reduced by adopting the brine.
Divalent calcium ions and divalent bromide ions in common calcium brine and bromine brine react with bicarbonate radicals in formation water to generate scales with different degrees, so that underground tools and formations are blocked, and the application range is limited. And a weighting agent is added into the well killing fluid, and a polymer is used as a suspending agent, but the temperature resistance effect is poor, and the system stability cannot be ensured.
In a possible implementation mode, 1% -2% of alkaline scale inhibitor is added to react with about 7000mg/L bicarbonate radical in formation water, so that reaction between brine and the bicarbonate radical in the formation water can be effectively prevented, and blockage of downhole tools and the formation due to scaling is avoided. Meanwhile, the density of the alkaline scale inhibitor is 1.40g/cm3The density of the brine is close to that of the brine, the hydrogen ion concentration index (pH value) is 13-14, the pH value of the brine can be automatically adjusted to about 7 from 4.5, the corrosion rate reaches the index of water corrosion standard 0.076mm/a (millimeter/year), and the current situation that the brine corrodes downhole tools is changed.
It should be noted that the basic scale inhibitor is a liquid scale inhibitor, and the well control fluid provided by the embodiment of the invention is a well control fluid suitable for formation water of sodium bicarbonate type.
In one possible implementation, the modified attapulgite is attapulgite treated by ultrasonic cavitation.
Other high density kill fluids currently in use, most employ biopolymers or multipolymers as thickeners to form the high density kill fluid. However, the field application has the following problems: firstly, the price of the polymer with the high temperature resistance of more than 120 ℃ reaches 3.5-10 ten thousand per ton, thus increasing the cost; secondly, the addition amount is large; and thirdly, the polymer is deeply invaded into the reservoir, so that the reservoir is greatly damaged and is not easy to flowback and block.
In the embodiment of the invention, the modified attapulgite can be used as a thickening agent of the well control fluid. The modified attapulgite is attapulgite subjected to ultrasonic cavitation treatment. Because the natural attapulgite has the phenomenon of crystal polymerization, the cavitation effect of the ultrasonic cavitation treatment can generate local high-temperature and high-pressure environment, the instantaneous acting force is large, the polymerization of the attapulgite can be well impacted and dispersed, the attapulgite is uniformly dispersed, and the space active sites of the attapulgite are increased. Therefore, the modified attapulgite improves the dispersibility of the attapulgite and solves the problems of little free water and difficult dispersion in high-density brine. In addition, the modified attapulgite can also shorten the stirring time of the well killing fluid and the swelling time of each component, so that the well killing fluid can be thickened quickly. In addition, the modified attapulgite is fibrous after water absorption expansion and dispersion, and can also play a bridging role in the well killing fluid.
The control fluid provided by the embodiment of the invention can accurately control the volume increase of the control fluid by adding brine, and is convenient for preparing the control fluid with accurate density. By adding the alkaline scale inhibitor and cooperating with other components, the method has the functions of inhibiting the brine from invading a reservoir and reacting with bicarbonate radicals in formation water to generate precipitates in the operation process, automatically adjusting the pH value of the brine, reducing the corrosion rate of the brine and avoiding the brine from corroding underground tools in the operation process. Through adding the modified attapulgite and cooperating with other components, the space active sites of the attapulgite can be increased, a suspension network structure with stable adsorptivity is formed, and the modified attapulgite is uniformly dispersed in brine. Through adding oil-soluble temporary plugging agent, defoaming agent, wetting agent, calcium carbonate to with other component mating reaction, make this kill fluid be difficult for the seepage to get into the hydrocarbon reservoir, thereby avoid causing the injury to the hydrocarbon reservoir, and be difficult for appearing the sediment, do not have the bubble, do benefit to the pump and annotate to the operation position. After the well killing fluid is adopted for operation, the recovery rate of the oil well yield is over 90 percent, and meanwhile, the well killing fluid is automatically released and flowback along with the operation negative pressure.
By adding calcium carbonate and matching with other components, the calcium carbonate has the advantages of adjustable density, acid solubility and temporary plugging, and plays a role of a key medicament for rheological stability of the whole well control fluid system when being added into the well control fluid, and is equivalent to three purposes. In particular, in the aspect of temporary plugging, an oil-soluble temporary plugging agent and fibrous modified attapulgite are matched according to the bridging principle to form a compact and loose temporary plugging layer, and the temporary plugging can be automatically removed through back drainage. Compared with a polymer as a thickening agent, the well control fluid provided by the embodiment of the invention greatly reduces the damage to the stratum caused by the fact that the well control fluid invades the stratum deeply. In addition, the addition of calcium carbonate directly affects the stability of the well killing fluid at high temperature, and causes the fluctuation of the density of a well killing fluid system.
The defoaming agent is added to effectively prevent the well killing fluid from generating a large amount of bubbles, so that the density of the well killing fluid is unstable. The density of the well killing fluid can be increased by adding calcium carbonate, so that the well killing fluid can be conveniently settled to a well killing operation position.
The surface activity of attapulgite and brine can be changed by adding the wetting agent, the surface tension of the well killing fluid and the interfacial tension between the well killing fluid and crude oil are reduced, the retention time of the well killing fluid in a reservoir is shortened, and the well killing fluid is quickly drained. In the embodiment of the invention, the mass percentage of the brine can be 62%, 65%, 68%, 70%, 80%, 85% and the like. The alkaline scale inhibitor may be 1%, 1.2%, 1.4%, 1.5%, 1.7%, 1.8%, 1.9%, etc. in mass%. The oil-soluble temporary plugging agent can be 0.5%, 0.6%, 0.7%, 0.8%, 0.9%, 1.0% and the like by mass percent. The modified attapulgite clay may be present in an amount of 4%, 4.5%, 5%, 5.5%, 6%, 6.5%, 7%, etc. by mass. The calcium carbonate may be present in an amount of 7%, 10%, 15%, 17%, 20%, 25%, 30%, etc. by mass. The wetting agent may be 0.2%, 0.25%, 0.3%, 0.35%, 0.4%, 0.45%, 0.5%, etc. in mass%.
The brine density can be 1.35g/cm3、1.36g/cm3、1.37g/cm3、1.38g/cm3、1.39g/cm3、1.40g/cm3And the like. The concentration of calcium ions in the brine may be 14g/L, 15g/L, 16g/L, 17g/L, 18g/L, 19g/L, etc. The pH of the basic scale inhibitor may be 13, 13.3, 13.5, 13.8, 14, etc. The acid solubility of the calcium carbonate may be 90%, 91%, 92%, 93%, 94%, 95%, 96%, etc.
In one possible implementation, the basic scale inhibitor is an organic amine polymer scale inhibitor. The organic amine polymer scale inhibitor can be synthesized by amino trimethylene phosphonic acid and dioctyl sodium sulfosuccinate.
By adding 1-2% of organic amine polymer scale inhibitor, the scale inhibitor can react with about 7000mg/L bicarbonate radical in formation water, and can effectively prevent the scale formation phenomenon caused by the reaction of brine and the bicarbonate radical. Meanwhile, the density of the organic amine polymer scale inhibitor is 1.40g/cm3Sealing with brineThe degree is similar, the pH value is more than or equal to 13, the pH value of the brine can be automatically adjusted from 4.5 to 6.7, the corrosion rate reaches the index of the water corrosion standard of 0.076mm/a, the corrosion rate of the brine is reduced, and the current situation that the calcium brine corrodes downhole tools is changed.
In one possible implementation, the oil-soluble temporary plugging agent is oxidized asphalt powder.
In one possible implementation, the oil solubility of the oxidized asphalt powder is 56% to 73%. The oxidized asphalt powder has good stability at high temperature and can be softened at high temperature. The adhesive force among all components in the well killing fluid can be enhanced by adding the oxidized asphalt powder, so that the well killing fluid forms a thin and compact temporary plugging zone of an oil-gas reservoir, and the well killing fluid is effectively prevented from leaking into the oil-gas reservoir to cause damage to the oil-gas reservoir. And the oxidized asphalt powder has high thermal stability and acid and alkali resistance, and is beneficial to enhancing the thermal stability and acid and alkali resistance of the well killing fluid.
In one possible implementation, the particle size of the oxidized asphalt powder is in the range of 20-280 meshes. For example, the particle size of the oxidized asphalt powder is 20 mesh, 50 mesh, 100 mesh, 150 mesh, 200 mesh, 350 mesh, 280 mesh, or the like. The selected asphalt oxide powder with the particle size range is beneficial to enhancing the dispersibility of the asphalt oxide powder in the well killing fluid and better playing a temporary plugging role.
In one possible implementation, the particle size of the modified attapulgite is in the range of 200-600 mesh. For example, the particle size of the modified attapulgite is 200 mesh, 300 mesh, 400 mesh, 500 mesh, 600 mesh, or the like. The modified attapulgite with the particle size range is selected for use, so that the adsorption force among all components of the well killing fluid can be effectively increased, and the consistency of the well killing fluid is increased, so that a suspension net structure with stable adsorptivity can be formed with brine, the suspension net structure has good colloid properties such as unique dispersion, high temperature resistance, saline alkali resistance and the like, and the risk of well killing operation is reduced.
In one possible implementation, the particle size of the calcium carbonate ranges from 80 to 320 mesh. For example, the particle size of calcium carbonate is 80 mesh, 100 mesh, 150 mesh, 200 mesh, 250 mesh, 300 mesh, or the like. The calcium carbonate with the particle size range is selected, and the oxidized asphalt powder and the modified attapulgite with different particle sizes are matched, so that the leakage prevention and stopping capacity of the well killing fluid is improved to a certain extent.
In one possible implementation, the acid solubility of calcium carbonate is 90% to 96%. The higher acid solubility of the calcium carbonate is easily dissolved in the well killing fluid, so that the calcium carbonate solid is prevented from caking and influencing the fluidity of the well killing fluid.
In one possible implementation, the defoamer is at least one of tributyl phosphate and white oil.
The tributyl phosphate comprises 99.5 to 100 mass percent of pure tributyl phosphate.
Tributyl phosphate and white oil are selected as defoaming agents, so that a film with formed foam is in an unstable state and can be quickly defoamed.
In one possible implementation mode, the wetting agent is a mixture of methanol and ethylene glycol monobutyl ether, and the volume ratio of the methanol to the ethylene glycol monobutyl ether is 23-29: 17-23. The methanol comprises 99.5 to 100 mass percent of pure methanol; the ethylene glycol monobutyl ether comprises 99.5-100% by mass of pure ethylene glycol monobutyl ether.
In one possible embodiment, methanol alone can be used as the wetting agent, ethylene glycol monobutyl ether alone can be used as the wetting agent, or a mixture of methanol and ethylene glycol monobutyl ether can be used as the wetting agent. In the embodiment of the present invention, this is not particularly limited. Wherein when a mixture of methanol and ethylene glycol monobutyl ether is used, the volume ratio of the methanol to the ethylene glycol monobutyl ether is 23-29: 17-23. For example, the volume ratio of methanol to ethylene glycol monobutyl ether can be 23: 17, 26: 20 or 29: 20. in addition, other additives may be included in the mixture. In the examples of the present invention, the volume ratio of methanol to ethylene glycol monobutyl ether and other additives are not particularly limited.
The mixture of methanol and ethylene glycol monobutyl ether is selected as a wetting agent, so that the surface activity of attapulgite and brine can be changed, the surface tension of the well killing fluid and the interfacial tension between the well killing fluid and crude oil are reduced, the retention time of the well killing fluid in a reservoir is shortened, and the well killing fluid can be quickly drained.
In a second aspect, an embodiment of the present invention provides a method for preparing a well control fluid, where the method includes:
step 1: adding the brine into a stirring tank according to the mass percentage of each component.
The components by mass percent are 61.6-87.1 percent of brine, 1-2 percent of alkaline scale inhibitor, 0.5-1.0 percent of oil-soluble temporary plugging agent, 4-7 percent of modified attapulgite, 7-30 percent of calcium carbonate, 0.2-0.5 percent of wetting agent and the balance of defoaming agent. According to the mass percent of the components, adding a certain mass percent of brine into a stirring tank.
The brine contains impurities such as silt, large particulate matters and the like, so that the brine added is the brine after precipitation and filtration.
Step 2: adding an alkaline scale inhibitor into the stirring tank, and uniformly stirring.
The specific process of the step is as follows: adding a certain mass percent of alkaline scale inhibitor into a stirring tank with brine, and uniformly stirring.
Wherein, the stirring time can be set and changed according to the requirement. In the examples of the present invention, the stirring time is not particularly limited. For example, the time of stirring may be 30min, 40min, or 50 min. Preferably, the stirring time is 40 min.
And step 3: adding the modified attapulgite into the stirring tank, and uniformly stirring.
The specific process of the step is as follows: adding a certain mass percentage of modified attapulgite into a stirring tank added with brine and an alkaline scale inhibitor, and uniformly stirring.
And 4, step 4: adding the defoaming agent into the stirring tank, and uniformly stirring.
The specific process of the step is as follows: adding a certain mass percent of defoaming agent into a stirring tank added with brine, alkaline scale inhibitor and modified attapulgite, and uniformly stirring.
And 5: adding a wetting agent into the stirring tank, and uniformly stirring.
The specific process of the step is as follows: adding a wetting agent in a certain mass percentage into a stirring tank added with brine, an alkaline scale inhibitor, modified attapulgite and a defoaming agent, and uniformly stirring.
Step 6: and adding calcium carbonate and an oil-soluble temporary plugging agent into the stirring tank, and uniformly stirring to obtain the well killing fluid.
The specific process of the step is as follows: adding a certain mass percentage of calcium carbonate and an oil-soluble temporary plugging agent into a stirring tank added with brine, an alkaline scale inhibitor, modified attapulgite, a defoaming agent and a wetting agent, and uniformly stirring to obtain the well killing fluid.
The preparation method of the well killing fluid is simple and easy to prepare, can accurately control the volume increase of the well killing fluid, and is convenient to prepare the well killing fluid with accurate density. In addition, the well killing fluid has low cost, meets the well killing operation requirement, reduces the cost and saves resources.
The technical solution of the present invention will be described in detail by specific examples below.
In the following examples, those whose operations are not subject to the conditions indicated, are carried out according to the conventional conditions or conditions recommended by the manufacturer. The raw materials are conventional products which can be obtained commercially by manufacturers and specifications.
Wherein, the brine is the waste of industrial soda ash and is purchased from Hongkong oil field petroleum engineering research institute. An organic amine polymer scale inhibitor purchased from the institute of oil engineering in Hongkong oil field. Oxidized asphalt powder, available from Tianjin Pude technology, Inc. Modified attapulgite from Tianjin Pude technology. A mixture of methanol and ethylene glycol monobutyl ether purchased from the hong kong oil field oil engineering research institute.
Example 1
This example provides a density of 1.430g/cm3The well killing fluid is prepared by the following method:
87.1 percent of the mixture by mass and 1.40g/cm of the density3Adding the brine into a stirring tank; slowly adding 1% of organic amine polymer scale inhibitor into the stirring tank, and uniformly stirring; adding 4% of modified attapulgite into a stirring tank, and uniformly stirring; adding 0.2 percent of tributyl phosphate into the stirring tank,stirring uniformly; adding a mixture of 0.2% of methanol and ethylene glycol monobutyl ether into a stirring tank, wherein the volume ratio of the methanol to the ethylene glycol monobutyl ether is 26: 20, stirring uniformly; 7% of 300-mesh calcium carbonate and 0.5% of oxidized asphalt powder are added into a stirring tank and stirred uniformly to obtain the well killing fluid provided by the embodiment.
Example 2
This example provides a density of 1.430g/cm3The well killing fluid is prepared by the following method:
the mass percentage is 79 percent and the density is 1.35g/cm3Adding the brine into a stirring tank; slowly adding 1.5% of organic amine polymer scale inhibitor into the stirring tank, and uniformly stirring; adding 5% of modified attapulgite into a stirring tank, and uniformly stirring; adding 0.2% of tributyl phosphate into the stirring tank, and uniformly stirring; adding a mixture of 0.3% of methanol and ethylene glycol monobutyl ether into a stirring tank, wherein the volume ratio of the methanol to the ethylene glycol monobutyl ether is 29: 20, stirring uniformly; 13% of calcium carbonate of 200 meshes and 1.0% of oxidized asphalt powder are added into a stirring tank and stirred uniformly to obtain the well killing fluid provided by the embodiment.
Example 3
This example provides a density of 1.500g/cm3The well killing fluid is prepared by the following method:
the weight percentage is 73.8 percent and the density is 1.40g/cm3Adding the brine into a stirring tank; slowly adding 1.5% of organic amine polymer scale inhibitor into the stirring tank, and uniformly stirring; adding 7% of modified attapulgite into a stirring tank, and uniformly stirring; adding 0.3% of white oil into the stirring tank, and uniformly stirring; adding a mixture of 0.4% of methanol and ethylene glycol monobutyl ether into a stirring tank, wherein the volume ratio of the methanol to the ethylene glycol monobutyl ether is 23: 17, stirring uniformly; 16% of 350-mesh ultrafine calcium carbonate and 1.0% of oxidized asphalt powder are added into a stirring tank and stirred uniformly to obtain the well killing fluid provided by the embodiment.
Example 4
This example provides a density of 1.510g/cm3Well killingThe well killing fluid is prepared by the following method: :
the weight percentage is 66.2 percent and the density is 1.35g/cm3Adding the brine into a stirring tank; slowly adding 1.5% of organic amine polymer scale inhibitor into the stirring tank, and uniformly stirring; adding 5% of modified attapulgite into a stirring tank, and uniformly stirring; adding 0.2% of tributyl phosphate into the stirring tank, and uniformly stirring; adding a mixture of 0.3% of methanol and ethylene glycol monobutyl ether into a stirring tank, wherein the volume ratio of the methanol to the ethylene glycol monobutyl ether is 26: 23, stirring uniformly; 26% of calcium carbonate with 400 meshes and 0.8% of oxidized asphalt powder are added into a stirring tank and stirred uniformly to obtain the well killing fluid provided by the embodiment.
Example 5
This example provides a density of 1.550g/cm3The well killing fluid is prepared by the following method:
the weight percentage is 67.7 percent and the density is 1.38g/cm3Adding the brine into a stirring tank; slowly adding 2% of organic amine polymer scale inhibitor into the stirring tank, and uniformly stirring; adding 5% of modified attapulgite into a stirring tank, and uniformly stirring; adding 0.4% of tributyl phosphate into the stirring tank, and uniformly stirring; adding a mixture of 0.4% of methanol and ethylene glycol monobutyl ether into a stirring tank, wherein the volume ratio of the methanol to the ethylene glycol monobutyl ether is 26: 17, stirring uniformly; and adding 24% of 500-mesh calcium carbonate and 0.5% of oxidized asphalt powder into a stirring tank, and uniformly stirring to obtain the well killing fluid provided by the embodiment.
Example 6
This example provides a density of 1.600g/cm3The well killing fluid is prepared by the following method:
the weight percentage is 61.6 percent and the density is 1.40g/cm3Adding the brine into a stirring tank; slowly adding 2% of organic amine polymer scale inhibitor into the stirring tank, and uniformly stirring; adding 5% of modified attapulgite into a stirring tank, and uniformly stirring; adding 0.4% of tributyl phosphate into the stirring tank, and uniformly stirring; adding 0.5% methanol and ethylene glycol into a stirring tankA mixture of monobutyl ether wherein the volume ratio of methanol to ethylene glycol monobutyl ether is 29: 23, stirring uniformly; 30% of 600-mesh calcium carbonate and 0.5% of oxidized asphalt powder are added into a stirring tank and stirred uniformly to obtain the well killing fluid provided by the embodiment.
Comparative example 1
This comparative example provides a density of 1.550g/cm3The well killing fluid is prepared by the following method:
according to the mass percent of each component, 40.82 percent of tap water is added into the stirring tank; dividing 37.14% by mass of sodium formate into 6 equal parts, adding 5 equal parts of 30.95% by mass of sodium formate into a stirring tank, stirring for 1 hour, slowly adding the rest 1 equal part of 6.19% by mass of sodium formate after dissolving, and stirring for dissolving; adding 2.78% by mass of attapulgite into a stirring tank, stirring while adding, and stirring for more than 2 hours; and adding 19.26 mass percent of calcium carbonate into the stirring tank, stirring while adding, and stirring for more than 2 hours to obtain the well killing fluid provided by the comparative example.
It should be noted that the attapulgite used in comparative example 1 was natural attapulgite.
As shown in table 1, table 1 includes six properties, each of which corresponds to a different index. The six kinds of well killing fluids provided in the embodiments 1 to 6 are respectively subjected to measurement of various properties by applying the embodiments 1 to 5, and whether the well killing fluids provided in the embodiments 1 to 6 meet indexes corresponding to the corresponding properties in the table 1 or not is determined, so that whether the well killing fluids meet requirements in a well killing operation process or not is determined.
TABLE 1 Performance index of kill fluid
| Serial number | Performance of | Index (I) |
| 1 | Density, g/cm3 | 1.430-1.600 |
| 2 | Viscosity retention (170 ℃ C.),%) | 80.0 |
| 3 | Core permeability recovery% | ≥90.00 |
| 4 | Sand bed filtration loss, mL | ≤25 |
| 5 | Scale inhibition effect of filtrate | The test tube wall is transparent |
| 6 | Corrosion rate (100 ℃ C.) mm/a | ＜0.076 |
Application example 1
The density of the control fluids provided in examples 1 to 6 and comparative example 1 was evaluated in this application example. The specific evaluation process comprises the following steps: 350mL of the well killing fluid provided by the embodiments 1-6 and the comparative example 1 are respectively taken and respectively filled into seven high-temperature aging tanks, and the well killing fluid is fully and uniformly stirred. The density of each kill fluid was measured three times with a densitometer and averaged as shown in table 2 below. Then seven high-temperature aging tanks are respectively placed into a high-temperature roller heating furnace and are kept at 170 ℃ for 72 hours. The mixture was cooled to room temperature of 25 c, stirred for 5 minutes, the density of each kill fluid was measured three times with a densitometer, and the average was taken and recorded in table 2 below, and the density difference was finally calculated. Specific test data are shown in table 2.
TABLE 2 evaluation of control fluid Density stability
As can be seen from table 2: the control fluid provided in comparative example 1 was maintained at 170 ℃ for 72 hours, cooled to room temperature, and then subjected to density measurement with a density difference of 0.012g/cm3Greater than standard + -0.01 g/cm3Indicating that the kill fluid system is unstable. Compared with the well killing fluid provided by the comparative example 1, the well killing fluid provided by the examples 1-6 is kept at 170 ℃ for 72 hours, and after being cooled to room temperature, the density measurement is carried out, wherein the error is 0.0088g/cm3Less than standard + -0.01 g/cm3And the well killing fluid in the embodiments 1-6 is 1.430-1.600g/cm3Within the range, the density index in the table 1 is met, and the safety requirement of on-site high-temperature well construction can be met.
Application example 2
The application examples evaluate the viscosities of the control fluids provided in examples 1 to 6 and comparative example 1. The specific evaluation process comprises the following steps: 350mL of the well killing fluid provided by the embodiments 1-6 and the comparative example 1 are respectively taken and respectively filled into seven high-temperature aging tanks, and the well killing fluid is fully and uniformly stirred. Measuring the apparent viscosity of each well control fluid by using a six-speed rotational viscometer for three times, and calculating the average value to obtain the apparent viscosity mu of each well control fluid before test1The results are shown in Table 3 below. Then seven high-temperature aging tanks are respectively placed into a high-temperature roller heating furnace and are kept at 170 ℃ for 72 hours. Cooling to room temperature of 25 ℃, measuring the apparent viscosity of each well killing fluid by using a six-speed rotational viscometer for three times, and calculating the average value to obtain the apparent viscosity mu of each well killing fluid after the test2The viscosity retention φ was finally calculated, as shown in Table 3 below.
Viscosity protectionThe calculation formula of the retention rate is as follows:
wherein mu2To the apparent viscosity after the test, μ1To obtain the apparent viscosity before the test, φ represents the viscosity retention. Specific test data are shown in table 3.
TABLE 3 evaluation of kill fluid viscosity stability
| Well killing fluid | μ1，mpa·s | μ2，mpa·s | φ，％ |
| Example 1 | 44 | 41.3 | 93.8 |
| Example 2 | 41 | 38 | 92.6 |
| Example 3 | 46.5 | 45.3 | 97.4 |
| Example 4 | 48 | 46.8 | 97.5 |
| Example 5 | 52 | 60 | 115 |
| Example 6 | 56 | 65 | 116 |
| Comparative example 1 | 61 | 84 | 137 |
As can be seen from table 3: the viscosity retention rate of the well control fluid provided by the comparative example 1 is 137%, although the index requirement that the viscosity retention rate is greater than 80% in the table 1 is met, the viscosity retention rate is too high, which indicates that the well control fluid has high thixotropy, and the viscosity is too high to facilitate the flow of the well control fluid. Compared with the well killing fluid provided by the comparative example 1, the viscosity retention rates of the well killing fluids provided by the examples 1 to 6 are all larger than 90%, and the index requirements that the viscosity retention rates are larger than 80% in the table 1 are met, which indicates that the structure of the well killing fluid is not changed, the high-temperature resistance effect of the well killing fluid is good, and the stability is strong. The modified attapulgite in the well killing fluid provided by the embodiment of the invention is beneficial to increasing the consistency of the well killing fluid, suspending solid calcium carbonate and preventing the calcium carbonate from sinking into a shaft to block a hydrocarbon reservoir.
It should be noted that, although the viscosity retention rates of the killing fluids provided in examples 5 and 6 are greater than 100%, the viscosity retention rates of the killing fluids provided in examples 5 and 6 are both smaller than that of the killing fluid provided in comparative example 1, and the viscosity retention rates of the killing fluids provided in examples 5 and 6 are both smaller than 120%, and are within the range of allowable variation of the viscosity retention rates. Therefore, the well killing fluid provided by the embodiments 5 and 6 meets the construction safety requirement of the on-site high-temperature well.
Application example 3
The application examples evaluate the fluid loss of the control fluids provided in examples 1 to 6 and comparative example 1. The specific evaluation process comprises the following steps: adding clay with the mass being 20% of that of the quartz sand into the quartz sand with the size of 30-40 meshes, uniformly mixing the quartz sand and the clay, drying, pouring the mixture into a sand bed, wherein the sand bed is provided with scale marks, and pouring the uniformly mixed quartz sand and clay to the first scale mark. The same volume of kill fluid from examples 1-6 and comparative example 1 was poured slowly onto 7 sand beds, respectively, to the second scale mark. The fluid loss of the kill fluid provided in each example on each sand bed was determined using a sand bed fluid loss gauge. Specific test data are shown in table 4.
TABLE 4 evaluation of loss prevention of kill fluid
| Well killing fluid | 1.0MPa immersion, mL | 1.0MPa fluid loss, mL | Remarks for note |
| Example 1 | 60 | 16.7 | / |
| Example 2 | 38 | 0 | Immersed in a sand bed of 4.3 cm |
| Examples3 | 42 | 0 | Immersed in a sand bed of 4.8 cm |
| Example 4 | 51 | 0 | Immersed in a sand bed of 5.3 cm |
| Example 5 | 68 | 15.5 | / |
| Example 6 | 72 | 19.8 | / |
| Comparative example 1 | 320 | All lose | All loss of |
As can be seen from table 4: comparative example 1 provides a kill fluid system in which the majority of the components are in particulate form and the kill fluid does not form a temporary plug. There are voids in the sand bed, and as the pressure increases, the kill fluid flows out along the voids in the sand bed under the influence of the pressure. It can be seen from the preparation methods of the above examples 1 to 6 that a certain amount of the oxidized asphalt powder is added in each example, the amount of the oxidized asphalt powder in examples 1, 5 and 6 is 0.5%, the amount of the oxidized asphalt powder in example 4 is 0.8%, and the amount of the oxidized asphalt powder in examples 2 and 3 is 1.0%. As can be seen from Table 4, the sand beds in examples 1, 5 and 6 had some fluid loss, but the fluid loss was < 25 mL. While the sand bed in examples 2, 3 and 4 had no fluid loss after the oxidized asphalt powder had been increased. Therefore, the well killing fluids in the embodiments 1 to 6 all meet the requirement that the filtration loss of the sand bed is less than or equal to 25mL in the table 1, and the filtration loss of the sand bed can be influenced by the change of the amount of the oxidized asphalt powder, the amount of the oxidized asphalt powder can be properly increased, so that the filtrate can be reduced from entering an oil-gas layer, and a certain protection effect on a sensitive oil-gas layer can be realized.
Application example 4
The application example evaluates the corrosion rate of the well killing fluid provided in examples 1 to 6. The application example is mainly used for evaluating the well killing fluid provided by examples 1-6 according to whether the corrosion rate of the N80 steel sheet reaches the water corrosion standard index at the temperature of 100 ℃. The specific test method is based on SY T0026-1999 Water corrosivity test method, and the test data are shown in Table 5.
TABLE 5 evaluation of kill fluid erosion Rate
As can be seen from table 5, a certain amount of organic amine polymer scale inhibitor is added to the well killing fluid provided in examples 1 to 6, the organic amine polymer scale inhibitor is a basic scale inhibitor, the pH is not less than 13, and the pH of the well killing fluid can be automatically adjusted to about 7 and is near neutral. As can be seen from the corrosion rate of the kill fluid provided in examples 1 to 6 on N80 steel sheets, when the addition amount of the organic amine polymer scale inhibitor is 1%, the corrosion rate is 0.076mm/a, and then the corrosion rate gradually decreases with the increase of the addition amount of the organic amine polymer scale inhibitor, and the corrosion rates all meet the index that the water corrosion standard is less than 0.076 mm/a.
In addition, the corrosion rate of the well control fluid without the alkaline scale inhibitor is measured by the application example. The well killing fluid without the alkaline scale inhibitor is prepared by the following method: 87.1 percent of the mixture by mass and 1.40g/cm of the density3Adding the brine into a stirring tank; adding 4% of modified attapulgite into a stirring tank, and uniformly stirring; adding 0.2% of tributyl phosphate into the stirring tank, and uniformly stirring; adding 0.2 percent of the mixture into a stirring tankThe mixture of the methanol and the ethylene glycol monobutyl ether is uniformly stirred; adding 7% of 300-mesh calcium carbonate and 0.5% of oxidized asphalt powder into a stirring tank, and uniformly stirring to obtain the well killing fluid without the alkaline scale inhibitor.
Under the same conditions as above, the control fluid without the alkaline scale inhibitor was determined to have a pH of 4.55, be acidic, have a corrosion rate of 0.147mm/a, greater than the water corrosion standard of 0.076mm/a, and cause severe corrosion to the downhole tool.
From the above, it can be seen that: compared with the well killing fluid without the alkaline scale inhibitor, the well killing fluid provided by the embodiments 1-6 reduces the corrosion rate of the downhole tool and meets the normal use of the downhole tool.
In the present application example, the pH value of the well-killing fluid is measured by an electronic portable pH meter.
Application example 5
The application example evaluates the permeability of the well killing fluid provided by the examples 1-6, and the specific evaluation process is that the air permeability is 1 × 10-3μm2＜Ka＜500×10-3μm2The test was performed on 7 crumb cores from the core port 338-1 Mingym group. Respectively immersing 1 piece of clastic core into saturated saline, after the clastic core is saturated in the saturated saline, measuring the permeability K of the original saturated saline before the clastic core is polluted by the well killing fluid0. The rock core is not moved, the joint of the permeability recovery rate tester is adjusted to reversely displace the well killing fluid provided by the embodiment 1 under the flow rate of 0.4 times, the displacement is stopped after the displacement of 2 times of the volume, the saturated saline water is positively displaced by more than 20 times of the volume after being soaked for 120min to reach stable pressure and flow rate, the damage rate of the well killing fluid to the rock core is measured, and the permeability K of the saturated saline water after the well killing fluid pollutes the chip rock core is read0d. The permeability recovery ω is then calculated.
The permeability recovery is calculated by the formula:
wherein, K0dPermeability of saturated brine after contamination of clastic cores with kill fluid, K0For breaking of well killing fluidThe permeability of the original saturated brine before the core of the chip, omega is the permeability recovery rate.
The permeability recovery of the kill fluids provided in examples 2-6 was sequentially determined. Specific test data are shown in table 6.
TABLE 6 evaluation of permeability recovery after kill fluid filtrate contamination
As can be seen from Table 6, the tested permeability recovery values of the control fluids provided in examples 1 to 6 are all greater than 90%, and the requirements of the control fluids in Table 1 for the permeability recovery rate of not less than 90% are met, which indicates that the control fluids in examples 1 to 6 can meet the requirements of oil reservoir protection.
Application example 6
The application example evaluates the scale inhibition effect of the well killing fluid provided by the examples 1 to 6. The specific evaluation process comprises the following steps: 5g/l NaHCO is prepared3Solution to simulate bicarbonate in formation water. Taking the well killing fluid provided in example 1 as an example, NaHCO is added in a volume ratio of 1:1350mL of the solution and 50mL of the filtrate of the kill fluid provided in example 1 were mixed and put into a closed measuring cylinder with a plug, and the mixture was placed in a water bath at 100 ℃ for 72 hours, and the filtrate was poured out, and the glass wall of the measuring cylinder with a plug was visually observed for the presence of scale. Similarly, the above tests were carried out on the control fluids provided in examples 2 to 6, and the specific test data are shown in table 7.
TABLE 7 evaluation of scale inhibition Capacity of kill fluid
| Well killing fluid | 100℃/72h | Remarks for note |
| Example 1 | Is free of | The wall of the measuring cylinder is transparent |
| Example 2 | Is free of | The wall of the measuring cylinder is transparent |
| Example 3 | Is free of | The wall of the measuring cylinder is transparent |
| Example 4 | Is free of | The wall of the measuring cylinder is transparent |
| Example 5 | Is free of | The wall of the measuring cylinder is transparent |
| Example 6 | Is free of | The wall of the measuring cylinder is transparent |
As can be seen from Table 7, the filtrates of the kill fluids of examples 1-6 were mixed with NaHCO, respectively3The mixed solution of the solution does not scale on the wall of the measuring cylinder with a plug, which indicates that the filtrate of the well killing fluid does not react with NaHCO3The solution reacts to generate precipitate, namely the scale inhibitor added into the well killing fluid can effectively prevent high-concentration calcium ions and high-concentration magnesium ions in the brine from reacting with bicarbonate radicals in the formation water and the like to generate precipitate. Therefore, the well killing fluids provided in examples 1 to 6 satisfy the scale inhibition effect on the filtrate in Table 1And (5) fruit requirements.
Application example 7
The application example optimizes the particle size and components of the calcium carbonate used in examples 1 to 6, and the calcium carbonate is too fine in particle size, easy to agglomerate, too coarse in suspension and easy to sink. Therefore, the particle size and the component ratio of the calcium carbonate are optimized by measuring the rheological property of the medium-pressure well fluid in the embodiments 1 to 6, and the aim of improving the stability and the suspension property of the system is fulfilled. Specific test data are shown in table 8.
TABLE 8 calcium carbonate component screening
As can be seen from table 8, the main components listed in the table are B13, B16, B18, B20, C1, C2, C3, and C4, wherein the particle sizes of B13, B16, B18, and B20 are all 200 mesh, the particle sizes of C1 and C2 are all 600 mesh, and the particle sizes of C3 and C4 are all 1800 mesh. The well killing fluid obtained by different combinations of the components meets the aims of relatively stable density before and after high temperature and relatively stable viscosity before and after high temperature. Therefore, the present application example was screened from both the density difference before and after high temperature and the viscosity retention rate before and after high temperature. As can be seen from table 8: b13 has a large density difference and a low viscosity retention; the density difference of B16 is large, and the viscosity retention rate is too high; the viscosity retention of C3 and C4 was too high; the density difference of B20 is large. Therefore, according to the density difference before and after high temperature and the viscosity retention rate before and after high temperature, 200-mesh B18, 600-mesh C1 and C2 can be selected to prepare the well killing fluid provided by the embodiment of the invention, so that the density of the well killing fluid is increased, and the well killing fluid can be conveniently settled to a well killing operation position.
It should be noted that, for any one of the components in the above table, if the density of the component is low, overflow is easily caused; high density and easy pollution to oil-gas layer. And the density difference before and after high temperature is too large, which indicates that the component is unstable and is easily influenced by high temperature. In addition, if the ingredient has a low viscosity retention, it is liable to precipitate; if the viscosity retention is too high, thixotropy is large, and field use is affected. Therefore, when selecting the calcium carbonate component, the screening can be performed by combining the above two aspects.
In summary, the well killing fluid provided by the embodiment of the invention is a well killing fluid with higher density, and can meet the requirements in the well killing operation process.
The above description is only for facilitating the understanding of the technical solutions of the present invention by those skilled in the art, and is not intended to limit the present invention. Any modification, equivalent replacement, or improvement made within the spirit and principle of the present invention should be included in the protection scope of the present invention.
Claims (10)
1. The well killing fluid is characterized by comprising the following components in percentage by mass:
61.6 to 87.1 percent of brine, 1 to 2 percent of alkaline scale inhibitor, 0.5 to 1.0 percent of oil-soluble temporary plugging agent, 4 to 7 percent of modified attapulgite, 7 to 30 percent of calcium carbonate, 0.2 to 0.5 percent of wetting agent and the balance of defoaming agent;
the density of the brine is 1.35-1.43 g/cm3The brine comprises calcium ions with the concentration of 14-19 g/L;
the density of the alkaline scale inhibitor is 1.40g/cm3The hydrogen ion concentration index is 13-14;
the modified attapulgite is attapulgite subjected to ultrasonic cavitation treatment.
2. The kill fluid of claim 1, wherein the basic scale inhibitor is an organic amine polymer scale inhibitor.
3. The kill fluid of claim 1, wherein the oil-soluble temporary plugging agent is an oxidized asphalt powder.
4. The kill fluid of claim 3, wherein the oxidized asphalt powder has an oil solubility of 56-73% and a particle size in the range of 20-280 mesh.
5. The kill fluid of claim 1, wherein the modified attapulgite has a particle size in the range of 200 to 600 mesh.
6. The kill fluid of claim 1, wherein the calcium carbonate has a particle size in the range of 80 to 320 mesh.
7. The kill fluid of claim 6, wherein the calcium carbonate has an acid solubility of 90% to 96%.
8. The kill fluid of claim 1, wherein the defoamer is at least one of tributyl phosphate and white oil.
9. The well killing fluid of claim 1, wherein the wetting agent is a mixture of methanol and ethylene glycol monobutyl ether, and the volume ratio of the methanol to the ethylene glycol monobutyl ether is 23-29: 17-23.
10. A method of preparing the kill fluid of any of claims 1 through 9, comprising:
adding the brine into a stirring tank according to the mass percentage of each component;
adding an alkaline scale inhibitor into the stirring tank, and uniformly stirring;
adding modified attapulgite into the stirring tank, and uniformly stirring;
adding a defoaming agent into the stirring tank, and uniformly stirring;
adding a wetting agent into the stirring tank, and uniformly stirring;
and adding calcium carbonate and an oil-soluble temporary plugging agent into the stirring tank, and uniformly stirring to obtain the well killing fluid.
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