Polymer fracturing fluid for offshore oilfield and preparation method thereof

Abstract

The invention discloses a polymer fracturing fluid for an offshore oilfield and a preparation method of the polymer fracturing fluid. The polymer fracturing fluid for the offshore oilfield is prepared from the following components in percentage by mass: 1.0 to 3.0 percent of bio-based modified polymer, 0.3 to 1.0 percent of dual-response gel breaker, 0.5 to 1.5 percent of seawater compatibility aid and the balance of pretreated seawater, the bio-based modified polymer is a copolymer of polyglucuronic acid grafted 2-acrylamide-2-methylpropanesulfonic acid, and the grafting rate is 15 to 25 percent; the double-response gel breaker is a compound of an organosilicon compound containing a boric acid ester bond and a calcium alginate microcapsule. The fracturing fluid disclosed by the invention has excellent temperature resistance and shear resistance, is suitable for high-temperature fracturing construction of a deep well, and ensures that the fracturing fluid keeps good sand-carrying performance and crack propagation capability in the construction process; the fracturing fluid system has good wall building property and low filtration loss, the damage rate of the gel breaking fluid to the permeability of a rock core matrix is lower than 6% and far lower than the upper limit of 30% of the industrial standard, the reservoir structure is effectively protected, and the oil gas flow-back efficiency and productivity performance after fracturing are improved.

Description

Technical Field

[0001] This invention relates to a polymer fracturing fluid for offshore oil fields and its preparation method, belonging to the field of petroleum engineering technology. Background Technology

[0002] In offshore oilfield fracturing operations, the performance of fracturing fluids directly impacts reservoir stimulation effectiveness and marine environmental protection requirements. Traditional techniques typically use petroleum-based polymers (such as polyacrylamide) as the main agent, adding chemical breaker such as persulfate to achieve fracturing, and relying on fresh water for preparation to avoid the impact of salt ions on system stability. While such fracturing fluids can meet basic proppant carrying requirements under normal salinity conditions, their insufficient salt tolerance has become increasingly apparent with the advancement of deep-sea high-salinity reservoir development. Furthermore, the fracturing process relies on the precise application of chemical agents, and the low biodegradability of petroleum-based materials means that the fracturing fluid is prone to residual metal ions and organic pollutants, making it difficult to meet increasingly stringent marine environmental standards. In addition, traditional fluid preparation processes rely on freshwater transportation, which poses challenges to operational efficiency and cost control in scenarios where space is limited on offshore platforms and freshwater reserves are scarce.

[0003] However, existing fracturing fluid systems face significant technical bottlenecks in terms of environmental friendliness, controllable gel breaking, and adaptability to complex marine environments. Specifically: petroleum-based polymers generally have a biodegradability rate of less than 30%, resulting in high concentrations of metal ions such as Fe³⁺ in the gel breaking fluid, which can easily cause long-term pollution to the marine ecosystem; single chemical breaker relies on high-temperature triggering, leading to long gel breaking times and uncontrollable processes, and incomplete or premature gel breaking is likely to occur in low-temperature or high-salinity environments; ordinary polymers are prone to salt precipitation and aggregation in seawater with NaCl concentrations exceeding 100,000 ppm, resulting in viscosity decay rates exceeding 30%, which cannot meet the fracturing requirements of deep-sea high-salinity reservoirs. Furthermore, the polymer swelling time in traditional fluid preparation processes generally exceeds 60 minutes and requires freshwater adjustment, making it difficult to adapt to the actual needs of rapid operations and environmentally friendly fluid preparation on offshore platforms. Therefore, developing a novel fracturing fluid system that combines environmental friendliness, salt resistance, controllable gel breaking, and process adaptability has become an urgent need for efficient development and green operations in offshore oilfields. Therefore, a polymer fracturing fluid for offshore oilfields is proposed. Summary of the Invention

[0004] The purpose of this invention is to provide a polymer fracturing fluid for offshore oil fields and its preparation method, which can achieve a new fracturing fluid system with environmental friendliness, salt resistance, controllable gel breaking and process adaptability.

[0005] The polymer fracturing fluid for offshore oil fields provided by this invention has the following mass percentage composition: Bio-based modified polymer 1.0-3.0%, bi-responsive breaker 0.3-1.0%, seawater compatibility agent 0.5-1.5%, balance pretreated seawater; The bio-based modified polymer is a copolymer of polyglucuronic acid grafted with 2-acrylamide-2-methylpropanesulfonic acid, with a grafting rate of 15-25%. The dual-response de-gelling agent is a compound of an organosilicon compound containing borate ester bonds and calcium alginate microcapsules.

[0006] The preparation method of the bio-based modified polymer includes the following steps: Crude polyglucuronic acid, prepared by fermentation of Pseudomonas marineis, was dissolved in deionized water to prepare a solution with a mass concentration of 5-10%. 10-20% of 2-acrylamide-2-methylpropanesulfonic acid monomer and 0.5-1.0% of potassium persulfate initiator were added. The reaction was carried out at 50-60℃ under nitrogen protection for 3-4 hours. After precipitation with ethanol and freeze-drying, the graft copolymer was obtained.

[0007] The preparation method of the crude polyglucuronic acid includes the following steps: Pseudomonas marinensis is inoculated into a fermentation medium (containing 20 g / L glucose, 5 g / L yeast extract, seawater base solution, pH 7.2) and fermented at 30℃ and 200 rpm for 48 hours; the fermentation broth is centrifuged (10000 rpm, 10 min) to collect the cells, washed with 0.1 M NaCl solution, and then ultrasonically disrupted (20 kHz, 5 min) to extract crude polysaccharide; the crude product is dialyzed (molecular weight cutoff 10 kDa) and freeze-dried to obtain crude polyglucuronic acid (purity ≥85%, verified by infrared spectroscopy).

[0008] Preferably, the bio-based modified polymer has a water content of ≤5% (mass percentage) and a particle size distribution D50 of 50-80 μm.

[0009] Preferably, the organosilicon compound containing borate ester bonds has the structural formula (CH2=CH)Si(OCH2CH2OBO2C6H4)3, which can be synthesized by refluxing vinyltrichlorosilane with 4-hydroxyphenylboronic acid in ethanol, and its hydrolysis half-lives at 40℃, 60℃, and 80℃ are 12h, 6h, and 2h, respectively. The mass ratio of the organosilicon compound containing borate ester bonds to the calcium alginate microcapsules is 2-5:1.

[0010] Preferably, the calcium alginate microcapsules have a particle size of 50-100 μm, a wall thickness of 5-10 μm, and a core material of a supersaturated MgCl2 solution with a degree of 1.2-1.5. After contact with seawater, the MgCl2 solution contains MgCl2 within 30 minutes. 2+ Release rate ≥80%.

[0011] Preferably, the seawater compatibility additive is a surfactant composed of polyethylene glycol (molecular weight 6000) and sodium dodecyl sulfate in a mass ratio of 3:1, with a hydrophilic-lipophilic balance (HLB) value of 12-14 to ensure the stability of the fracturing fluid in seawater.

[0012] Preferably, the pretreated seawater is obtained by two-stage filtration, which includes a 5μm primary filtration and a 1μm fine filtration. The pretreated seawater has a post-turbidity ≤0.5 NTU, a particle size >5 μm content <0.05%, and Ca... 2+ Concentration of 400-500 ppm, Mg 2+ The concentration is 1200-1500 ppm.

[0013] The properties of the polymer fracturing fluid of this invention are as follows: After shearing at 120℃ and a shear rate of 170s⁻¹ for 2 hours, the viscosity retention rate is ≥85%; In seawater with a NaCl concentration of 200,000 ppm, the initial viscosity at 25℃ is 65-75 mPa·s, and the viscosity decay rate after 72 hours is ≤8%. The viscosity of the breaking solution is ≤5 mPa·s (45℃, breaking time 4-6h), and the biodegradability (ISO14855, 28 days) is ≥92%, with Fe content... 3+ Ion concentration < 0.08 mg / L.

[0014] The present invention also provides a method for preparing the polymer fracturing fluid, comprising the following steps: S1. Adjust the pH of the pretreated seawater to 7.8±0.2 and add bio-based modified polymer for swelling; S2. Seawater compatibility additives and dual-response breaker are added sequentially, and polymer fracturing fluid is obtained by stirring and shearing.

[0015] The preparation is preferably carried out in a three-bladed propeller stirrer with a diameter of 1 / 3 of the reaction vessel. The bio-based modified polymer powder is sprinkled in at a speed of ≤5g / min at a speed of 400rpm, and the torque fluctuation is monitored until it is <5%, and the swelling time is 35±5 minutes.

[0016] The method of the present invention includes the following steps for detecting viscosity: using a Brookfield DV-III viscometer to detect 170s⁻¹ viscosity, with a target value of 60-70 mPa·s, and fine-tuning the pH to 7.5-8.5 with 0.1 mol / L HCl / NaOH solution, with each adjustment amount ≤0.5 mL / 100 L.

[0017] The fracturing fluid prepared by the method of the present invention is sealed in nitrogen gas, stored at a temperature ≤25℃, with a viscosity decay rate ≤10% after 30 days of storage, and a biodegradable bacterial growth rate ≤10³CFU / m.

[0018] This invention uses a bio-based modified polymer (polyglucuronic acid grafted AMPS) as the main agent. By introducing strongly hydrophilic sulfonic acid groups, the molecular chain stability of the polymer in high-salt environments is effectively enhanced. Experimental data show that under conditions with NaCl concentrations as high as 200,000 ppm, the initial viscosity of the fracturing fluid can reach 75 mPa·s, and the viscosity decay rate after 72 hours does not exceed 8%, which is significantly better than traditional polyacrylamide fracturing fluids (the decay rate can reach more than 35%), meeting the fracturing requirements of deep-sea high-salt reservoirs.

[0019] This invention innovatively employs a dual-response breaker compound consisting of a boron ester bond-containing organosilicon compound and calcium alginate microcapsules, possessing a dual triggering mechanism of temperature and seawater ions. This mechanism can achieve complete debonding within 4-6 hours in the 40-80℃ range, with a debonding solution viscosity ≤5 mPa·s, and requires no additional chemical breaker, avoiding the problem of residual Fe³⁺ and other metal ions in traditional breakers, thus significantly improving environmental performance.

[0020] The fracturing fluid of this invention exhibits excellent temperature and shear resistance performance, with a viscosity retention rate of ≥85% after continuous shearing at 120℃ and a shear rate of 170s⁻¹ for 2 hours. It is suitable for high-temperature fracturing operations in deep wells, ensuring that the fracturing fluid maintains good sand-carrying capacity and fracture propagation ability during the operation.

[0021] The fracturing fluid system of this invention has good wall-building properties and low filtration loss. The damage rate of the core matrix to the permeability of the rupture fluid is less than 6%, which is far below the industry standard upper limit of 30%, effectively protecting the reservoir structure and improving the efficiency of oil and gas flowback and production performance after fracturing. Attached Figure Description

[0022] Figure 1 is a flowchart of the preparation of fracturing fluid according to the present invention. Detailed Implementation

[0023] Unless otherwise specified, the experimental methods used in the following examples are conventional methods.

[0024] Unless otherwise specified, all materials and reagents used in the following examples are commercially available.

[0025] The following example illustrates the preparation method of polyglucuronic acid by fermentation with Pseudomonas marinensis: Pseudomonas marinensis was inoculated into a fermentation medium (containing 20 g / L glucose, 5 g / L yeast extract, seawater base solution, pH 7.2) and fermented at 30°C and 200 rpm for 48 hours; the fermentation broth was centrifuged at 10,000 rpm for 10 min to collect the cells, then washed with 0.1 M NaCl solution and ultrasonically disrupted at 20 kHz for 5 min to extract crude polysaccharide; the crude product was dialyzed and freeze-dried to obtain crude polyglucuronic acid.

[0026] The borate ester organosilicon used in the following examples has the structural formula (CH2=CH)Si(OCH2CH2OBO2C6H4)3, and its hydrolysis half-lives at 40℃, 60℃, and 80℃ are 12h, 6h, and 2h, respectively.

[0027] The calcium alginate microcapsules used in the following examples have a particle size of 50-100 μm, a wall material thickness of 5-10 μm, and a core material of a supersaturated MgCl2 solution with a degree of 1.2-1.5. After contact with seawater, the Mg... 2+ Release rate ≥80%.

[0028] Example 1 This embodiment takes the preparation of a polymer fracturing fluid for offshore oil fields as an example: a fracturing fluid for conventional seawater environments. Objective: To verify the comprehensive performance of the bio-based modified polymer main agent (grafting rate 20%) and the dual-response breaker (mass ratio 3:1) in a conventional seawater environment.

[0029] Preparation of bio-based modified polymer: 100g of crude polyglucuronic acid fermented by marine Pseudomonas aeruginosa was dissolved in 1000mL of deionized water, 20g of AMPS monomer and 1g of potassium persulfate were added, and the reaction was carried out at 55℃ under nitrogen protection for 3.5 hours. After precipitation with ethanol, the graft copolymer was obtained by freeze drying (grafting rate 20%, determined by infrared spectroscopy).

[0030] Seawater pretreatment: Seawater from an oilfield in the South my country Sea was subjected to a 5μm primary filtration + a 1μm fine filtration, resulting in a turbidity of 0.3 NTU. 0.1% NaOH was added to adjust the pH to 7.8.

[0031] Solution preparation process: Using a three-bladed propeller stirrer with a diameter of 1 / 3 of the reaction vessel, 20g of graft copolymer (accounting for 2.0% of the total amount) was uniformly added at 400rpm. After 35 minutes, the torque fluctuation was <5%. Add 10g of a compound of polyethylene glycol 6000 and sodium dodecyl sulfate in a mass ratio of 3:1 (accounting for 1.0% of the total fracturing fluid). Add 6g of dual-response decolliding agent (containing borate ester organosilicon: calcium alginate microcapsules = 3:1, accounting for 0.6% of the total) through an 80-mesh sieve, and stir at 100rpm for 10 minutes; Viscosity was measured at 68 mPa·s (170 s). -1 Adjust the pH to 7.6 to obtain the finished fracturing fluid.

[0032] Implementation results: Initial properties: viscosity at 25℃ is 68 mPa·s, viscosity after standing in 35000 ppm seawater for 72 h is 63 mPa·s (attenuation rate 7.4%). Debriding performance: Debriding time at 45℃ for 5 hours, viscosity of the broken liquid 4.2 mPa·s, Mg 2+ Release rate 82%; Environmental indicators: Biodegradation rate 93% (28 days), Fe 3+ Concentration 0.06 mg / L.

[0033] Example 2 This embodiment takes the preparation of a polymer fracturing fluid for offshore oil fields as an example: a salt-resistant fracturing fluid with a high grafting rate. Objective: To verify the effect of high grafting rate (25%) on improving high salt tolerance.

[0034] The amount of graft copolymer was adjusted to 3.0%, the amount of AMPS monomer added was 25g (grafting rate 25%), and the ratio of dual-response deblaster was 5:1 (10g). The other steps are the same as in Example 1, except that artificial high-salinity seawater (NaCl concentration 200,000 ppm) is used.

[0035] Implementation results: Salt resistance: Initial viscosity at 25℃ is 75 mPa·s, viscosity at 72h is 69 mPa·s (attenuation rate 8%). Temperature resistance: viscosity after shearing at 120℃ for 2 hours is 52 mPa·s (retention rate 86.7%). Breaking time: 4 hours at 60℃, surface tension of the breaking liquid is 28mN / m (facilitating backflow).

[0036] Example 3 This embodiment uses the preparation of a polymer fracturing fluid for offshore oil fields as an example: for verifying its gel breaking performance in low-temperature environments. Objective: To verify the temperature-responsive gel breaking mechanism (hydrolysis half-life of 12h at 40℃).

[0037] The breaker contains borate ester organosilicon compounds in a 4:1 ratio (microcapsule addition accounts for 0.4% of the fracturing fluid, and borate ester organosilicon compounds account for 1.6% of the fracturing fluid). After seawater pretreatment, Ca... 2+ / Mg2+ The concentration should be controlled at 1200-1500 ppm; After the fracturing fluid is prepared, it is placed in a 40℃ constant temperature water bath, and the viscosity is checked regularly.

[0038] Implementation results: The gel breaking time at 40℃ was 10 hours (gradual hydrolysis of borate ester bonds), and the viscosity of the gel breaking solution was 4.8 mPa·s; When not in contact with seawater, Mg 2+ Release rate <5% (microcapsules did not swell), proving that the temperature-triggered single decomposition pathway is effective.

[0039] Example 4 This embodiment uses the preparation of a polymer fracturing fluid for offshore oil fields as an example: for microcapsule particle size optimization. Objective: To verify the effect of calcium alginate microcapsule particle size (D50=75μm) on the release rate of the degrading agent.

[0040] By adjusting the sodium alginate concentration to control the microcapsule particle size, microcapsules with D50=75μm were screened (measured by laser particle size analyzer, which meets the requirement of 5-10μm wall thickness). The other components and steps are the same as in Example 1.

[0041] Implementation results: Mg²15 min after contact with seawater + Release rate 60%, reaching 85% within 30 minutes; The breaking time was shortened to 4.5 hours, proving that particle size optimization improves breaking efficiency.

[0042] Example 5 This embodiment uses the preparation of a polymer fracturing fluid for offshore oil fields as an example: for verification of rapid fluid preparation process. Objective: To verify the effect of stirring process on polymer swelling time (35±5 minutes).

[0043] Using a three-bladed stirrer with a diameter of 1 / 3 of the reaction vessel, the feeding speed was 5 g / min at 400 rpm; Monitor torque changes; if the torque fluctuation is less than 5% after 32 minutes, swelling is confirmed to be complete.

[0044] Implementation results: The swelling time is 32 minutes, which is 46.7% more efficient than the traditional stirring process (60 minutes). The system showed good homogeneity after preparation, with no particulate precipitate (observed after standing for 24 hours).

[0045] Comparative Example 1 This comparison provides conventional petroleum-based fracturing fluids.

[0046] Purpose of implementation: To compare the performance differences between the fracturing fluid of this invention and commercially available petroleum-based products (containing polyacrylamide as the main agent and persulfate breaker).

[0047] Formula: 2.0% polyacrylamide, 0.5% potassium persulfate, balance is pretreated seawater; Preparation process: conventional stirring and dissolution, without microencapsulation protection process.

[0048] Implementation results: Initial properties: viscosity at 25℃ is 65 mPa·s, viscosity in 35000ppm seawater for 72 hours is 42 mPa·s (attenuation rate 35.4%). Debriding performance: Debriding time at 45℃ for 8 hours, viscosity of the debriding liquid is 8 mPa·s (not meeting the requirement of ≤5 mPa·s); Environmental indicators: Biodegradation rate 28% (28 days), Fe 3+ The concentration was 1.2 mg / L (far exceeding the 0.08 mg / L of this invention).

[0049] Application Example 1 This application example provides a comparative experiment on salt tolerance and biodegradability.

[0050] Experimental objective: To verify the differences in viscosity stability and biodegradability between the fracturing fluid of the present invention (Example 1) and the traditional petroleum-based fracturing fluid (Comparative Example 1) under high-salt conditions.

[0051] Experimental steps: 1. Experimental Materials and Equipment sample: The fracturing fluid of this invention (prepared in Example 1, NaCl concentration 35000ppm); Traditional petroleum-based fracturing fluid (comparative preparation, containing 2.0% polyacrylamide and 0.5% potassium persulfate).

[0052] equipment: Brookfield DV-III viscometer (shear rate 170s) -1 ); Incubator (controlled at 25℃±1℃); Biodegradation testing device (compliant with ISO 14855 standard, inoculated with activated sludge).

[0053] 2. Salt tolerance test Initial viscosity determination: Take 200 mL of each sample and measure the initial viscosity at 25 °C using a viscometer (shear rate 170 s⁻¹, reading after stabilization for 30 s).

[0054] 72h viscosity decay test: After sealing, the sample was placed in a 25℃ constant temperature oven. It was taken out every 24 hours, and after returning to room temperature, the viscosity was measured and the decay rate was calculated: viscosity decay rate = (1-72 hour viscosity / initial viscosity) × 100%.

[0055] 3. Biodegradation experiment Inoculation and culture: Take 100 mL of fracturing fluid sample, add 300 mL of activated sludge culture medium (MLSS=3000 mg / L), and place it on a shaker (150 rpm, 25℃). Regularly replenish the inorganic salt nutrient solution (containing NH4Cl 1g / L and K2HPO4 0.5g / L) to maintain microbial activity.

[0056] Degradation rate determination: Samples were taken on days 7, 14, and 28, and the total organic carbon (TOC) content in the samples was determined by a TOC analyzer. The biodegradation rate was calculated as follows: Biodegradation rate % = (1 - sample TOC / initial TOC) × 100%.

[0057] 4.Fe 3+ Concentration detection After gel breaking, the sample was filtered through a 0.45 μm filter membrane, and the Fe content was determined using atomic absorption spectrometry. 3+ Concentration (wavelength 248.3nm, slit width 0.2nm).

[0058] Table 1 Comparison of fracturing fluid viscosity stability and biodegradability

[0059] in conclusion: The fracturing fluid of this invention exhibits viscosity stability in seawater at 35,000 ppm that of conventional products (7.4% vs 35.4% attenuation rate), meeting the stringent standard of "72h viscosity attenuation rate ≤ 8%" in claim 6. The biodegradability rate reaches 93%, which is 3.3 times higher than that of traditional petroleum-based fracturing fluids (28%), and Fe... 3+ The 95% reduction in residue demonstrates its significant environmental advantages.

[0060] Application Example 2 This application example provides a comparative experiment on the breaking time and triggering mechanism.

[0061] Experimental objective: The efficiency difference between the dual-response breaking mechanism (temperature + seawater ions) of the fracturing fluid of the present invention (Example 1, Example 3) and that of traditional chemical breaking agents was verified.

[0062] Experimental steps: 1. Experimental Samples Sample A: Dual-response fracturing fluid (Example 1, temperature + ion triggering, 0.6% breaker); Sample B: Single temperature-triggered fracturing fluid (Example 3, boron ester organosilicon compound and calcium alginate microcapsules were compounded at a ratio of 4:1, with 0.6% breaker). Sample C: Traditional chemical fracturing fluid (Comparative Example 1, containing 1.0% potassium persulfate).

[0063] 2. Setting the conditions for breaking the glue Temperature trigger test: Samples B and C were placed in constant temperature water baths at 40℃ and 50℃, respectively. Samples were taken every 1 hour to measure viscosity and record the gel breaking time (time when viscosity ≤ 5mPa·s).

[0064] Dual-response trigger test: Sample A was placed in a 45°C water bath, and artificial seawater (Mg²⁺) was added simultaneously. + Concentration 1500ppm, Ca² + (Concentration 500ppm), simulating a downhole environment, viscosity and Mg were measured every 30 minutes. 2+ Release rate (ICP spectrometer).

[0065] 3. Performance testing of the debonding liquid Viscosity was measured using a Brookfield viscometer (rotor No. 3, 170 s⁻¹, 45°C constant temperature bath). Mg 2+ Release rate: Take 10 mL of the gel-breaking solution, centrifuge, collect the supernatant, and determine the Mg²⁺ content. + Concentration, calculate release rate:

[0066] Table 2 Performance of fracturing fluid in breaking gels

[0067] in conclusion: The dual-response mechanism (sample A) shortened the gel breaking time by 50% compared to the single temperature triggering (sample B), demonstrating that seawater ions (Mg²⁺) + The synergistic effect of temperature significantly improves the efficiency of gel breaking; Compared with traditional chemical breakers (sample C), the amount of breaker used in this invention is reduced by 40%, the viscosity of the broken liquid is lower (4.2 mPa·s-8 mPa·s), and no additional chemical agents are required, thus avoiding secondary pollution, which fully achieves the design goal of the "dual breaking mechanism" of this invention.

[0068] Compared with Examples 1-5 and Comparative Example 1, it has significant advantages in the following aspects: salt resistance, breaking efficiency and mechanism, environmental performance breakthrough, temperature resistance and shear strength, and process efficiency. Salt tolerance comparison: Examples of this invention: In environments ranging from 35,000 ppm conventional seawater to 200,000 ppm high salinity, the viscosity decay rate after 72 hours was 7.4%-8% (Examples 1-2), significantly lower than the ≤8% specified in the claims, and far superior to the 35.4% of the comparative example. Example 2, with a high grafting rate (25%), achieved an initial viscosity of 75 mPa·s in 200,000 ppm brine, and maintained 69 mPa·s after 72 hours, demonstrating that the bio-based modified polymer effectively enhances the hydrophilicity of the molecular chain and inhibits the damage of salt ions to the polymer network through sulfonic acid group grafting.

[0069] Comparative example (traditional petroleum-based): The viscosity decay rate reached 35.4% at the same salinity. This is because the polyacrylamide molecular chains are prone to dehydration and aggregation in high salinity, resulting in poor system stability and failing to meet the requirements of high salinity marine operations.

[0070] Debonding efficiency and mechanism: Advantages of dual-response breaking: In Example 1 (temperature + ion triggering), the breaking time was 5 hours at 45°C, with a breaking solution viscosity of 4.2 mPa·s, which was 37.5% shorter than the 8 hours in the comparative example (chemical breaking agent), and the breaking agent dosage was reduced by 40% (0.6% vs 1.0%). In a low-temperature environment (40°C, Example 3), the breaking time was 10 hours via temperature triggering alone, demonstrating the hydrolysis of borate ester bonds and the interaction of seawater Mg... 2+ The synergistic effect significantly improves the controllability of debonding, avoiding the problems of traditional debonding agents relying on high temperature or excessive addition.

[0071] Microcapsule particle size optimization effect: Example 4: By adjusting the particle size of calcium alginate microcapsules (D50=75μm), Mg 2+ The release rate reached 85% within 30 minutes of contact with seawater, and the decomposition time was shortened to 4.5 hours, verifying the positive influence of microcapsule particle size on ion release rate and ensuring precise release of the decomposing agent.

[0072] Breakthrough in environmental performance: Biodegradation rate: The biodegradation rate of the present invention reached 92%-93% in 28 days (Examples 1-2), which far exceeded the 28% of the comparative example. This is because bio-based materials such as polyglucuronic acid can be decomposed into CO2 and H2O by marine microorganisms, which meets the IMO environmental standards.

[0073] Metal ion residue: Fe in the gel breaking solution 3+ The concentrations were all <0.08 mg / L (0.06 mg / L in Example 1), while Comparative Example 1 reached 1.2 mg / L. This is mainly because the persulfate breaker used in traditional fracturing fluids is prone to causing the dissolution of metal ions. This invention avoids the introduction of chemical breakers through a dual-response mechanism, reducing pollution from the source.

[0074] Temperature resistance, shear strength, and process efficiency: Temperature resistance: After shearing for 2 hours at 120°C for 170s⁻¹, the viscosity retention rate in Example 2 reached 86.7%. The cross-linked network of the nanocomposite structure (not explicitly stated in the examples, but covered by the claims) and the bio-based polymer effectively resisted high-temperature shear degradation.

[0075] Liquid preparation process: In Example 5, by optimizing the stirring speed (400 rpm) and the feeding rate (5 g / min), the polymer swelling time was shortened to 32 minutes, which is 46.7% more efficient than the traditional process (60 minutes). The system also has good uniformity (no precipitation), which meets the needs of rapid liquid preparation in the space-constrained environment of offshore platforms.

[0076] Those skilled in the art will recognize that the modules and algorithm steps of the various examples described in conjunction with the embodiments disclosed herein can be implemented in electronic hardware or a combination of computer software and electronic hardware. Whether these functions are implemented in hardware or software depends on the specific application and design constraints of the technical solution. Those skilled in the art can use different methods to implement the described functions for each specific application, but such implementation should not be considered beyond the scope of this application.

[0077] In addition, the functional modules in the various embodiments of this application can be integrated into one processing module, or each module can exist physically separately, or two or more modules can be integrated into one module.

[0078] The above description is merely a specific embodiment of this application, but the scope of protection of this application is not limited thereto. Any variations or substitutions that can be easily conceived by those skilled in the art within the scope of the technology disclosed in this application should be included within the scope of protection of this application. Therefore, the scope of protection of this application should be determined by the scope of protection of the claims.

[0079] In conclusion, the above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

Claims

1. A polymer fracturing fluid for offshore oil fields, comprising the following composition by mass percentage: Bio-based modified polymer 1.0-3.0%, bi-responsive breaker 0.3-1.0%, seawater compatibility agent 0.5-1.5%, balance pretreated seawater; The bio-based modified polymer is a copolymer of polyglucuronic acid grafted with 2-acrylamide-2-methylpropanesulfonic acid, with a grafting rate of 15-25%. The dual-response de-gelling agent is a compound of an organosilicon compound containing borate ester bonds and calcium alginate microcapsules.

2. The polymer fracturing fluid according to claim 1, characterized in that: The preparation method of the bio-based modified polymer includes the following steps: Crude polyglucuronic acid, prepared by fermentation of Pseudomonas marineis, was dissolved in deionized water to prepare a solution with a mass concentration of 5-10%. 10-20% of 2-acrylamide-2-methylpropanesulfonic acid monomer and 0.5-1.0% of potassium persulfate initiator were added. The reaction was carried out at 50-60℃ under nitrogen protection for 3-4 hours. After precipitation with ethanol and freeze-drying, the graft copolymer was obtained.

3. The polymer fracturing fluid according to claim 1 or 2, characterized in that: The bio-based modified polymer has a water content of ≤5% and a particle size distribution D50 of 50-80 μm.

4. The polymer fracturing fluid according to any one of claims 1-3, characterized in that: The structural formula of the organosilicon compound containing boron ester bonds is (CH2=CH)Si(OCH2CH2OBO2C6H4)3; The mass ratio of the organosilicon compound containing borate ester bonds to the calcium alginate microcapsules is 2-5:

1.

5. The polymer fracturing fluid according to any one of claims 1-4, characterized in that: The calcium alginate microcapsules have a particle size of 50-100 μm, a wall thickness of 5-10 μm, and a core material of a supersaturated MgCl2 solution with a degree of 1.2-1.

5. After contact with seawater, the Mg... 2+ Release rate ≥80%.

6. The polymer fracturing fluid according to any one of claims 1-5, characterized in that: The seawater compatibility additive is a surfactant composed of polyethylene glycol and sodium dodecyl sulfate in a mass ratio of 3:1, with a hydrophilic-lipophilic balance value of 12-14.

7. The polymer fracturing fluid according to any one of claims 1-6, characterized in that: The pretreated seawater is obtained by two-stage filtration, which includes a 5μm primary filtration and a 1μm fine filtration. The pretreated seawater has a post-turbidity ≤0.5 NTU, a particle size >5 μm content <0.05%, and Ca... 2+ Concentration of 400-500 ppm, Mg 2+ The concentration is 1200-1500 ppm.

8. A method for preparing the polymer fracturing fluid according to any one of claims 1-7, comprising the following steps: S1. Adjust the pH of the pretreated seawater to 7.8±0.2 and add bio-based modified polymer for swelling; S2. Seawater compatibility additives and dual-response breaker are added sequentially, and polymer fracturing fluid is obtained by stirring and shearing.

9. The preparation method according to claim 8, characterized in that: pH was adjusted using NaOH solution; The swelling time is 35 ± 5 minutes.

10. The application of the polymer fracturing fluid according to any one of claims 1-7 in offshore oilfield fracturing.

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