WO2019144442A1 - 一种自修复低伤害耐超高温压裂液 - Google Patents

一种自修复低伤害耐超高温压裂液 Download PDF

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WO2019144442A1
WO2019144442A1 PCT/CN2018/076070 CN2018076070W WO2019144442A1 WO 2019144442 A1 WO2019144442 A1 WO 2019144442A1 CN 2018076070 W CN2018076070 W CN 2018076070W WO 2019144442 A1 WO2019144442 A1 WO 2019144442A1
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fracturing fluid
high temperature
ultra
self
injury
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PCT/CN2018/076070
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English (en)
French (fr)
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毛金成
张阳
赵金洲
杨小江
张恒
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西南石油大学
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Priority to US16/071,081 priority Critical patent/US10633576B2/en
Publication of WO2019144442A1 publication Critical patent/WO2019144442A1/zh

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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
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/66—Compositions based on water or polar solvents
    • C09K8/68—Compositions based on water or polar solvents containing organic compounds
    • C09K8/685—Compositions based on water or polar solvents containing organic compounds containing cross-linking agents
    • 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
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/84—Compositions based on water or polar solvents
    • C09K8/86—Compositions based on water or polar solvents containing organic compounds
    • C09K8/88—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
    • C09K8/882—Compositions based on water or polar solvents containing organic compounds macromolecular compounds obtained by reactions only involving carbon-to-carbon unsaturated bonds
    • 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
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/84—Compositions based on water or polar solvents
    • C09K8/86—Compositions based on water or polar solvents containing organic compounds
    • C09K8/88—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
    • C09K8/887—Compositions based on water or polar solvents containing organic compounds macromolecular compounds containing cross-linking agents
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • 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
    • C09K2208/26—Gel breakers other than bacteria or enzymes

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  • the invention belongs to the technical field of oil and gas field development, and particularly relates to a self-repairing low-injury and ultra-high temperature fracturing fluid.
  • the traditional organic boron cross-linking fracturing fluid is only suitable for use at a temperature of 150 ° C, and it is difficult to maintain good performance above 180 ° C.
  • the long-chain polymer gum thickener is rapidly degraded when the temperature reaches 177°C, and the cross-linking structure of the vegetable gum fracturing fluid is hydrolyzed when the pH value of the system is low, especially at high temperature. . Therefore, with the increasing demand for ultra-high temperature fracturing fluids in oilfield operations, the high-temperature polymer fracturing fluid system with a maximum operating temperature of 200 ° C or even 220 ° C has been developed for the fracturing stimulation of low-permeability ultra-high temperature wells. Significance.
  • the present invention provides a self-repairing low-injury-resistant ultra-high temperature fracturing fluid to solve the technical problem that the conventional fracturing fluid is easily decomposed at high temperatures and affects performance.
  • the technical solution adopted by the present invention is to provide a self-repairing low-injury ultra-high temperature fracturing fluid, comprising the following mass percentage components: polymer thickener 0.4 wt% to 0.8 wt%, non- The metal cross-linking agent is 0.015 wt% to 0.02 wt%, the breaker is 0.04 wt% to 0.06 wt%, and the balance is water;
  • the polymer thickener is from 55 to 70:15 to 20:15 to 20 by weight ratio of acrylamide, acrylic acid, 2-acrylamido-2-methylpropanesulfonic acid, rigid monomer and cationic hydrophobic monomer. : 0.5 to 3: 0.1 to 1.0 is polymerized.
  • the present invention can also be improved as follows.
  • the self-repairing low-injury ultra-high temperature fracturing fluid comprises the following components by mass percentage: 0.6 wt% of polymer thickener, 0.015 wt% of non-metal cross-linking agent, 0.04 wt% of breaker, and the balance is water. .
  • non-metallic crosslinking agent is polyethyleneimine.
  • the breaker is an ammonium persulfate capsule and/or an over-current ammonium acid.
  • the rigid monomer is N-vinylpyrrolidone and/or sodium p-styrenesulfonate.
  • the cationic hydrophobic monomer is at least one of methyl diallyl ammonium chloride, methacryloyloxyethyl trimethyl ammonium chloride, and dimethyl octadecyl allyl ammonium chloride.
  • the polymer thickener is prepared by mixing acrylamide, acrylic acid, 2-acrylamido-2-methylpropanesulfonic acid, a rigid monomer and a cationic hydrophobic monomer in the range of 30 to 40 ° C. Polymerization is carried out for 8 to 10 hours to obtain a copolymer; then the copolymer is chopped, dried, and finally pulverized.
  • the maximum temperature of the fracturing fluid of the present invention sheared at 170 s -1 is as high as 220 ° C, and the maximum temperature of shearing at 100 s -1 is as high as 260 ° C, which can maintain its performance at high temperatures, which is an ideal Resistant to ultra high temperature fracturing fluid.
  • the preparation method of the polymer thickener is convenient to operate, low in cost, and has broad market prospects.
  • Figure 1 is a graph showing the apparent viscosity versus time for a high temperature fracturing fluid system at 170 s -1 and 180 °C;
  • Figure 2 is a graph showing the apparent viscosity versus time for a high temperature fracturing fluid system at 170 s -1 and 200 ° C;
  • Figure 3 is a graph showing the apparent viscosity versus time for a high temperature fracturing fluid system at 170 s -1 and 220 ° C;
  • Figure 4 is a graph showing the apparent viscosity versus time for a high temperature fracturing fluid system at 100 s -1 and 220 °C;
  • Figure 5 is a graph showing the apparent viscosity versus time for a high temperature fracturing fluid system at 100 s -1 and 240 °C;
  • Figure 6 is a graph showing the apparent viscosity versus time for a high temperature fracturing fluid system at 100 s -1 and 260 °C;
  • Figure 7 is a graph showing the apparent viscosity versus time for a silicone fracturing fluid system at 170 s -1 and 120 °C.
  • Embodiment 1 is a diagrammatic representation of Embodiment 1:
  • the polymer thickener was formulated into a 0.4 wt% solution, and 0.015 wt% of polyethyleneimine and 0.04 wt% of ammonium persulfate were added, and the mixture was thoroughly stirred to obtain a fracturing fluid.
  • the apparent viscosity of the high temperature fracturing fluid system as a function of time was measured at 170 s -1 and 180 ° C, as shown in Figure 1. It can be seen from Fig. 1 that the apparent viscosity of the high temperature resistant fracturing fluid drops sharply when the temperature rises. When the temperature reaches 180 ° C, the viscosity is 51 mPa ⁇ s, then the viscosity slowly rises and continues to shear at 180 ° C for 120 min.
  • the viscosity of the high temperature resistant fracturing fluid gradually rises, and the viscosity of the solution reaches 100 mPa ⁇ s, indicating that the self-repairing low-injury ultra-high temperature fracturing fluid of the present invention is self-repairing, thereby increasing the viscosity of the fracturing fluid system.
  • Embodiment 2 is a diagrammatic representation of Embodiment 1:
  • the polymer was formulated into a 0.4 wt solution, and 0.015 wt% of polyethyleneimine and 0.04 wt% of ammonium persulfate were added, and the mixture was thoroughly stirred to obtain a fracturing fluid.
  • the apparent viscosity of the high temperature fracturing fluid system as a function of time was measured at 170 s -1 and 200 ° C, as shown in Fig. 2. It can be seen from Fig. 2 that the apparent viscosity of the high temperature resistant fracturing fluid drops sharply when the temperature rises. When the temperature reaches 200 ° C, the viscosity is 45 mPa ⁇ s, then the viscosity slowly rises and continues to shear at 200 ° C for 120 min.
  • the viscosity of the high temperature resistant fracturing fluid gradually rises, and the viscosity of the solution reaches 80 mPa ⁇ s, indicating that the self-repairing low-injury ultra-high temperature fracturing fluid of the present invention is self-repairing, thereby increasing the viscosity of the fracturing fluid system.
  • Embodiment 3 is a diagrammatic representation of Embodiment 3
  • acrylamide, acrylic acid, 2-acrylamido-2-methylpropanesulfonic acid, sodium p-styrenesulfonate and methacryloyloxyethyltrimethylammonium chloride are used in a weight ratio.
  • the polymerization was initiated at 65 ° C for 15:17:15:2.0:1.0, and the copolymer was obtained after 10 hours of polymerization.
  • the copolymer was then chopped, dried at 40 ° C, and finally powdered to a sieve of 200 mesh to obtain a polymerization. Thickener powder.
  • the polymer was formulated into a 0.6 wt% solution, and 0.02 wt% of polyethyleneimine and 0.06 wt% of ammonium persulfate capsules were added, and the mixture was thoroughly stirred to obtain a fracturing fluid.
  • the apparent viscosity of the high temperature fracturing fluid system as a function of time was measured at 170 s -1 and 220 ° C, as shown in FIG. It can be seen from Fig. 3 that the apparent viscosity of the high temperature resistant fracturing fluid drops sharply when the temperature rises. When it reaches 220 ° C, the viscosity is 34 mPa ⁇ s, and the shearing is continued at 220 ° C for 120 min, and the viscosity is maintained at 34 mPa.
  • the self-repairing low-injury ultra-high temperature fracturing fluid of the present invention has the highest resistance at 170 s -1 .
  • the temperature is 220 °C.
  • Embodiment 4 is a diagrammatic representation of Embodiment 4:
  • This embodiment employs acrylamide, acrylic acid, 2-acrylamido-2-methylpropanesulfonic acid, N-vinylpyrrolidone, sodium p-styrenesulfonate and dimethyloctadecylallyl ammonium chloride.
  • the monomer was polymerized at a weight ratio of 65:17:15:1.0:1.0:1.0 at 40 ° C. After 8 hours of polymerization, a copolymer was obtained, and then the copolymer was chopped, dried at 40 ° C, and finally pulverized.
  • a polymer thickener powder was obtained by passing through a 250 mesh screen.
  • the polymer was formulated into a 0.6 wt% solution, and 0.015 wt% of polyethyleneimine and 0.04 wt% of ammonium persulfate were added, and the mixture was thoroughly stirred to obtain a fracturing fluid.
  • the apparent viscosity of the high temperature resistant fracturing fluid system as a function of time was measured at 100 s -1 and 220 ° C, as shown in FIG. It can be seen from Fig. 4 that when the temperature rises, the apparent viscosity of the high temperature resistant fracturing fluid drops sharply, the viscosity drops to 65 mPa ⁇ s, and then continues to shear at 220 °C to 120 min, and the viscosity of the high temperature resistant fracturing fluid rises slowly.
  • the viscosity of the solution reached 120 mPa ⁇ s, indicating that the self-repairing low-injury ultra-high temperature fracturing fluid of the present invention was self-repaired at this time, thereby increasing the viscosity of the fracturing fluid system.
  • Embodiment 5 is a diagrammatic representation of Embodiment 5:
  • This example uses acrylamide, acrylic acid, 2-acrylamido-2-methylpropanesulfonic acid, N-vinylpyrrolidone, methyldiallylammonium chloride and dimethyloctadecylallyl chloride.
  • the ammonium hexamethylene monomer was polymerized at a weight ratio of 65:17:15:2.0:0.5:0.5 at 30 ° C. After 10 hours of polymerization, a copolymer was obtained, and then the copolymer was chopped, dried at 40 ° C, and finally The powder was passed through a 250 mesh sieve to obtain a polymer thickener powder.
  • the polymer was formulated into a 0.6 wt% solution, and 0.015 wt% of polyethyleneimine and 0.04 wt% of ammonium persulfate were added, and the mixture was thoroughly stirred to obtain a fracturing fluid.
  • the apparent viscosity of the high temperature fracturing fluid system as a function of time was measured at 100 s -1 and 240 ° C, as shown in FIG. It can be seen from Fig. 5 that when the temperature rises, the apparent viscosity of the high temperature resistant fracturing fluid drops sharply, the viscosity drops to 51 mPa ⁇ s, and then continues to shear at 240 ° C to 120 min, and the viscosity of the high temperature resistant fracturing fluid rises slowly.
  • the solution viscosity reached 124 mPa ⁇ s, indicating that the self-repairing low-injury ultra-high temperature fracturing fluid of the present invention was self-repaired at this time, thereby increasing the viscosity of the fracturing fluid system.
  • the polymer was formulated into a 0.6 wt% solution, and 0.015 wt% of polyethyleneimine, 0.02 wt% of ammonium persulfate capsules, and 0.02 wt% of ammonium persulfate were added, and the mixture was thoroughly stirred to obtain a fracturing fluid.
  • the apparent viscosity of the high temperature fracturing fluid system as a function of time was measured at 100 s -1 and 260 ° C, as shown in FIG. It can be seen from Fig. 6 that the apparent viscosity of the high temperature resistant fracturing fluid drops sharply when the temperature rises. When the temperature reaches 260 ° C, the viscosity is 30 mPa ⁇ s, and the shearing is continued at 260 ° C for 120 min, and the viscosity is maintained at 35 mPa.
  • the maximum temperature resistance of the self-repairing low-injury ultra-high temperature fracturing fluid at 100 s -1 is 260 ° C.
  • a 0.5 wt% tannin solution was prepared, and 0.3 to 0.4% by weight of an organoboron crosslinking agent, 0.02% by weight of ammonium persulfate capsules, and 0.02% by weight of ammonium persulfate were added, and the mixture was thoroughly stirred to obtain a fracturing fluid.
  • the apparent viscosity of the silicone fracturing fluid system as a function of time was measured at 170 s -1 and 120 ° C, as shown in FIG. It can be seen from Fig. 7 that the apparent viscosity of the high temperature resistant fracturing fluid drops sharply when the temperature rises.
  • the viscosity of the fracturing fluid is slow. Slowly rising, the solution viscosity reached 132mPa ⁇ s, which was caused by the delayed cross-linking of the cross-linking agent, but then the viscosity of the fracturing fluid began to decrease and finally remained near 34mPa ⁇ s, indicating the thermal shearing action at this time.
  • the squeezing fracturing fluid system is destroyed, so the fracturing fluid cannot be used in reservoirs above 120 °C.

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Abstract

公开了一种自修复低伤害耐超高温压裂液，包括以下质量百分比的组分：聚合物稠化剂0.4wt％～0.8wt％，非金属交联剂0.015wt％～0.02wt％，破胶剂0.04wt％～0.06wt％，余量为水；其中，聚合物稠化剂由丙烯酰胺、丙烯酸、2-丙烯酰胺基-2-甲基丙磺酸、刚性单体和阳离子疏水单体按重量比为55～70:15～20:15～20:0.5～3:0.1～1.0聚合而成，聚合温度30～40℃，聚合时间8～10h。采用本压裂液，可有效解决传统压裂液在高温下容易分解而影响性能的技术问题。

Description

一种自修复低伤害耐超高温压裂液 技术领域
本发明属于油气田开发技术领域，具体涉及一种自修复低伤害耐超高温压裂液。
背景技术
近年来，随着世界对能源需求量的不断增加和勘探技术的进步，油气资源勘探开发不断向纵深发展，越来越多的主要勘探目的层呈现全面下沉的趋势，井深大于4500m，温度超过170℃的异常高温深井数日益增多，有的油井深度甚至超过了7000m，这些油井的温度达到了200℃。这对压裂液体系的耐温耐剪切性能提出了更高的要求，要求压裂液在200℃甚至220℃以上的储层温度下可以保持良好的流变性和携砂能力。而传统的有机硼交联压裂液仅适合在温度150℃下使用，很难在180℃以上保持良好的性能。常用植物胶稠化剂胍胶高分子长链在温度达到177℃时就迅速降解，且植物胶压裂液在体系pH值较低时，交联结构发生水解，尤其在高温下水解更为严重。因此，随着油田作业对超高温压裂液的需求日益加剧，针对低渗超高温井的压裂增产，研发最高使用温度可达200℃甚至220℃以上的耐高温聚合物压裂液体系具有重要意义。
发明内容
针对上述现有技术，本发明提供一种自修复低伤害耐超高温压裂液，以解决传统压裂液在高温下容易分解而影响性能的技术问题。
为了达到上述目的，本发明所采用的技术方案是：提供一种自修复低伤害耐超高温压裂液，包括以下质量百分比的组分：聚合物稠化剂0.4wt％～0.8wt％，非金属交联剂0.015wt％～0.02wt％，破胶剂0.04wt％～0.06wt％，余量为水；
其中，聚合物稠化剂由丙烯酰胺、丙烯酸、2-丙烯酰胺基-2-甲基丙磺酸、 刚性单体和阳离子疏水单体按重量比为55～70:15～20:15～20:0.5～3:0.1～1.0聚合而成。
在上述技术方案的基础上，本发明还可以做如下改进。
进一步，自修复低伤害耐超高温压裂液，包括以下质量百分比的组分：聚合物稠化剂0.6wt％，非金属交联剂0.015wt％，破胶剂0.04wt％，余量为水。
进一步，非金属交联剂为聚乙烯亚胺。
进一步，破胶剂为过硫酸铵胶囊和/或过流酸铵。
进一步，刚性单体为N-乙烯基吡咯烷酮和/或对苯乙烯磺酸钠。
进一步，阳离子疏水单体为甲基二烯丙基氯化铵、甲基丙烯酰氧乙基三甲基氯化铵和二甲基十八烷基烯丙基氯化铵中的至少一种。
进一步，聚合物稠化剂通过以下方法制备得到：将丙烯酰胺、丙烯酸、2-丙烯酰胺基-2-甲基丙磺酸、刚性单体和阳离子疏水单体混合，在30～40℃范围内聚合8～10h，得到共聚物；然后将共聚物剪碎、干燥，最后粉碎制得。
本发明的有益效果是：
1.压裂液在高温下体系内部的氢键作用、静电桥作用、缔合作用等会遭到破坏，其性能受到严重影响。本发明的压裂液虽然在高温下氢键作用、静电桥作用、缔合作用等也会遭到破坏，但这些作用在遭受破坏的同时，本发明的压裂液在水解和热解的双重作用下，各组分会发生相应的反应，形成更加稳定的共价键，使体系自身得到修复，压裂液性能不会受到影响。
2.本发明的压裂液在170s -1下剪切的最高温度高达220℃，在100s -1下剪切的最高温度高达260℃，在高温下也可以保持其性能，是一种理想的耐超高温压裂液。
3.聚合物稠化剂的制备方法操作方便，成本低廉，具有广阔的市场前景。
附图说明
为了更清楚地说明本发明实施例或现有技术中的技术方案，下面将对实施例或现有技术描述中所需要使用的附图作简单地介绍，显而易见地，下面描述中的附图仅仅是本发明的一些实施例，对于本领域普通技术人员来讲，在不付出创造性劳动性的前提下，还可以根据这些附图获得其他的附图。
图1是耐高温压裂液体系在170s -1、180℃下的表观粘度随时间的变化曲线；
图2是耐高温压裂液体系在170s -1、200℃下的表观粘度随时间的变化曲线；
图3是耐高温压裂液体系在170s -1、220℃下的表观粘度随时间的变化曲线；
图4是耐高温压裂液体系在100s -1、220℃下的表观粘度随时间的变化曲线；
图5是耐高温压裂液体系在100s -1、240℃下的表观粘度随时间的变化曲线；
图6是耐高温压裂液体系在100s -1、260℃下的表观粘度随时间的变化曲线；
图7是胍胶压裂液体系在170s -1、120℃下的表观粘度随时间的变化曲线。
具体实施方式
下面结合附图对本发明的具体实施方式做详细的说明。
实施例一：
本实施例采用丙烯酰胺、丙烯酸、2-丙烯酰胺基-2-甲基丙磺酸、N-乙烯基吡咯烷酮和二甲基十八烷基烯丙基氯化铵五种单体按重量比为60:20:18:1.5:0.1在30℃引发聚合，聚合10h后得到共聚物，然后将共聚物剪碎，在40℃条件下干燥，最后将其粉粹至过250目筛，得聚合物稠化剂粉末。将聚合物稠化剂配制成0.4wt％的溶液，并加入0.015wt％的聚乙烯亚胺与0.04wt％的过硫酸铵，充分搅拌后得到压裂液。
在170s -1、180℃下测试耐高温压裂液体系表观粘度随时间的变化曲线，如 图1所示。从图1可以看出当温度升高后，耐高温压裂液表观粘度急剧下降，当达到180℃时，粘度为51mPa·s，之后粘度慢慢上升，继续在180℃剪切至120min，耐高温压裂液粘度慢慢上升，溶液粘度达到了100mPa·s，说明此时本发明的自修复低伤害耐超高温压裂液进行了自我修复，从而使得压裂液体系的粘度上升。
实施例二：
本实施例采用丙烯酰胺、丙烯酸、2-丙烯酰胺基-2-甲基丙磺酸、N-乙烯基吡咯烷酮和甲基二烯丙基氯化铵五种单体按重量比为65:20:15:2.0:0.5在35℃引发聚合，聚合10h后得到共聚物，然后将共聚物剪碎，在40℃条件下干燥，最后将其粉粹至过250目筛，得聚合物稠化剂粉末。接着将聚合物配制成0.4wt的溶液，并加入0.015wt％的聚乙烯亚胺与0.04wt％的过硫酸铵，充分搅拌后得到压裂液。
在170s -1、200℃下测试耐高温压裂液体系表观粘度随时间的变化曲线，如图2所示。从图2可以看出当温度升高后，耐高温压裂液表观粘度急剧下降，当达到200℃时，粘度为45mPa·s，之后粘度慢慢上升，继续在200℃剪切至120min，耐高温压裂液粘度慢慢上升，溶液粘度达到了80mPa·s，说明此时本发明的自修复低伤害耐超高温压裂液进行了自我修复，从而使得压裂液体系的粘度上升。
实施例三：
本实施例采用丙烯酰胺、丙烯酸、2-丙烯酰胺基-2-甲基丙磺酸、对苯乙烯磺酸钠和甲基丙烯酰氧乙基三甲基氯化铵五种单体按重量比为65:17:15:2.0:1.0在30℃引发聚合，聚合10h后得到共聚物，然后将共聚物剪碎，在40℃条件下干燥，最后将其粉粹至过200目筛，得聚合物稠化剂粉末。接着将聚合物 配制成0.6wt％的溶液，并加入0.02wt％的聚乙烯亚胺与0.06wt％过硫酸铵胶囊，充分搅拌后得到压裂液。
在170s -1、220℃下测试耐高温压裂液体系表观粘度随时间的变化曲线，如图3所示。从图3可以看出当温度升高后，耐高温压裂液表观粘度急剧下降，当达到220℃时，粘度为34mPa·s，继续在220℃剪切至120min，粘度一直维持在34mPa·s附近，说明此时稠化剂的热破坏和聚乙烯亚胺与稠化剂的修复达到了动态平衡，因此本发明的自修复低伤害耐超高温压裂液在170s -1下的最高耐温为220℃。
实施例四：
本实施例采用丙烯酰胺、丙烯酸、2-丙烯酰胺基-2-甲基丙磺酸、N-乙烯基吡咯烷酮、对苯乙烯磺酸钠和二甲基十八烷基烯丙基氯化铵六种单体按重量比为65:17:15:1.0:1.0:1.0在40℃引发聚合，聚合8h后得到共聚物，然后将共聚物剪碎，在40℃条件下干燥，最后将其粉粹至过250目筛，得聚合物稠化剂粉末。接着将聚合物配制成0.6wt％的溶液，并加入0.015wt％的聚乙烯亚胺与0.04wt％的过硫酸铵，充分搅拌后得到压裂液。
在100s -1、220℃下测试耐高温压裂液体系表观粘度随时间的变化曲线，如图4所示。从图4可以看出当温度升高后，耐高温压裂液表观粘度急剧下降，粘度最低降为65mPa·s，之后继续在220℃剪切至120min，耐高温压裂液粘度慢慢上升，溶液粘度达到了120mPa·s，说明此时本发明的自修复低伤害耐超高温压裂液进行了自我修复，从而使得压裂液体系的粘度上升。
实施例五：
本实施例采用丙烯酰胺、丙烯酸、2-丙烯酰胺基-2-甲基丙磺酸、N-乙烯基吡咯烷酮、甲基二烯丙基氯化铵和二甲基十八烷基烯丙基氯化铵六种单体按重 量比为65:17:15:2.0:0.5:0.5在30℃引发聚合，聚合10h后得到共聚物，然后将共聚物剪碎，在40℃条件下干燥，最后将其粉粹至过250目筛，得聚合物稠化剂粉末。接着将聚合物配制成0.6wt％的溶液，并加入0.015wt％的聚乙烯亚胺与0.04wt％的过硫酸铵，充分搅拌后得到压裂液。
在100s -1、240℃下测试耐高温压裂液体系表观粘度随时间的变化曲线，如图5所示。从图5可以看出当温度升高后，耐高温压裂液表观粘度急剧下降，粘度最低降为51mPa·s，之后继续在240℃剪切至120min，耐高温压裂液粘度慢慢上升，溶液粘度达到了124mPa·s，说明此时本发明的自修复低伤害耐超高温压裂液进行了自我修复，从而使得压裂液体系的粘度上升。
实施例六：
本实施例采用丙烯酰胺、丙烯酸、2-丙烯酰胺基-2-甲基丙磺酸、N-乙烯基吡咯烷酮和二甲基十八烷基烯丙基氯化铵五种单体按重量比为65:17:15:2.0:1.0在30℃引发聚合，聚合10h后得到共聚物，然后将共聚物剪碎，在40℃条件下干燥，最后将其粉粹至过250目筛，得聚合物稠化剂粉末。接着将聚合物配制成0.6wt％的溶液，并加入0.015wt％的聚乙烯亚胺、0.02wt％的过硫酸铵胶囊和0.02wt％的过硫酸铵，充分搅拌后得到压裂液。
在100s -1、260℃下测试耐高温压裂液体系表观粘度随时间的变化曲线，如图6所示。从图6可以看出当温度升高后，耐高温压裂液表观粘度急剧下降，当达到260℃时，粘度为30mPa·s，继续在260℃剪切至120min，粘度一直维持在35mPa·s附近，说明此时稠化剂的热破坏和聚乙烯亚胺与稠化剂的修复达到了动态平衡，因此该自修复低伤害耐超高温压裂液在100s -1下的最高耐温为260℃。
对比例
配制0.5wt％的胍胶溶液，并加入0.3～0.4wt％的一种有机硼交联剂、0.02wt％的过硫酸铵胶囊和0.02wt％的过硫酸铵，充分搅拌后得到压裂液。在170s -1、120℃下测试胍胶压裂液体系表观粘度随时间的变化曲线，如图7所示。从图7可以看出当温度升高后，耐高温压裂液表观粘度急剧下降，当达到120℃时，粘度降为70mPa·s，然后继续在120℃进行剪切，压裂液粘度慢慢上升，溶液粘度达到了132mPa·s，这是因为交联剂的延迟交联作用导致，但随后压裂液粘度开始降低，并最终维持在34mPa·s附近，说明此时在热剪切作用下胍胶压裂液体系结构遭到破坏，因此该压裂液不能在超过120℃下的储层中使用。
虽然对本发明的具体实施方式进行了详细地描述，但不应理解为对本专利的保护范围的限定。在权利要求书所描述的范围内，本领域技术人员不经创造性劳动即可作出的各种修改和变形仍属本专利的保护范围。

Claims (8)

  1. 一种自修复低伤害耐超高温压裂液，其特征是，包括以下质量百分比的组分：聚合物稠化剂0.4wt％～0.8wt％，非金属交联剂0.015wt％～0.02wt％，破胶剂0.04wt％～0.06wt％，余量为水；
    其中，聚合物稠化剂由丙烯酰胺、丙烯酸、2-丙烯酰胺基-2-甲基丙磺酸、刚性单体和阳离子疏水单体按重量比为55～70:15～20:15～20:0.5～3:0.1～1.0聚合而成。
  2. 根据权利要求1所述的自修复低伤害耐超高温压裂液，其特征是，包括以下质量百分比的组分：聚合物稠化剂0.6wt％，非金属交联剂0.015wt％，破胶剂0.04wt％，余量为水。
  3. 根据权利要求1或2所述的自修复低伤害耐超高温压裂液，其特征是：所述非金属交联剂为聚乙烯亚胺。
  4. 根据权利要求1或2所述的自修复低伤害耐超高温压裂液，其特征是：所述破胶剂为过硫酸铵胶囊和/或过流酸铵。
  5. 根据权利要求1所述的自修复低伤害耐超高温压裂液，其特征是：所述刚性单体为N-乙烯基吡咯烷酮和/或对苯乙烯磺酸钠。
  6. 根据权利要求1所述的自修复低伤害耐超高温压裂液，其特征是：所述阳离子疏水单体为甲基二烯丙基氯化铵、甲基丙烯酰氧乙基三甲基氯化铵和二甲基十八烷基烯丙基氯化铵中的至少一种。
  7. 根据权利要求1所述的自修复低伤害耐超高温压裂液，其特征是，所述聚合物稠化剂通过以下方法制备得到：将丙烯酰胺、丙烯酸、2-丙烯酰胺基-2-甲基丙磺酸、刚性单体和阳离子疏水单体混合，在30～40℃范围内聚合8～10h，得到共聚物；然后将共聚物剪碎、干燥，最后粉碎制得。
  8. 如权利要求1～7任意一项所述的压裂液在180～260℃的超高温井的压裂改 造中的应用。
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CN111925618B (zh) * 2019-12-27 2022-08-16 成都华达能盛环保科技有限公司 一种无机复合材料掺杂的机械性能增强的树脂材料
CN112500845A (zh) * 2020-12-11 2021-03-16 中国石油天然气集团公司 一种海水基压裂液用稠化剂、压裂液及稠化剂制备方法
CN113429958A (zh) * 2021-07-01 2021-09-24 华美孚泰油气增产技术服务有限责任公司 一种自修复的压裂液增稠剂及其制备方法
CN114805663A (zh) * 2022-05-19 2022-07-29 中海油田服务股份有限公司 水基钻井液用流型调节剂及其制备方法

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