Graded injection cross-linked calcium alginate gel profile control agent for heterogeneous reservoir and profile control method

Abstract

The invention relates to a graded injection cross-linked calcium alginate gel profile control agent for a heterogeneous reservoir and a profile control method, the profile control agent comprises a core cross-linking system and a slow-release agent, and the dosage relation of the core cross-linking system and the slow-release agent is as follows: when the slow-release agent is added, the mass of the slow-release agent is 0.5%-1.0% of the mass of an SA solution in the core cross-linking system; during synergistic flooding, the mass of the slow-release agent is 0.3%-0.8% of the mass of the SA solution; the profile control method comprises the following steps: forming a cross-linking system by adopting high G type sodium alginate (G / M = 2) and 70mmol / L calcium carbonate solution, and adding gluconolactone GDL into an acidic reservoir (pH = 3) to regulate and control slow release of Ca < + >; according to the method, a graded injection strategy of injecting Ca < + > first and then injecting SA is adopted, in-situ crosslinking of gel in a deep high-permeability channel is achieved, and near-well blockage is avoided; the temperature, the pH and the mineralization degree are adaptively regulated and controlled; the plugging rate reaches up to 81.13%-87.56%, the recovery rate amplification exceeds 15%, the effect is better after cooperation with CO2 flooding, the problems that a traditional profile control agent is uneven in reaction, CO2 fluid channeling occurs, and remaining oil in a low-permeability area is difficult to use are effectively solved, and the profile control agent is suitable for medium-low-permeability high-water-content oil reservoirs.

Description

Technical Field

[0001] This invention relates to the technical field of improving oil recovery (EOR) in heterogeneous reservoirs in the field of oil extraction, specifically to a staged injection cross-linked calcium alginate gel profile control agent and a profile control method for heterogeneous reservoirs. Background Technology

[0002] After long-term waterflooding development, high-water-cut, heterogeneous oil reservoirs tend to form dominant flow channels, causing injected fluid to surge along high-permeability zones. This makes it difficult to effectively utilize the remaining oil in low-permeability areas, becoming a key issue restricting oil supply. In existing technologies, older oilfields often use silicate-based profile control agents: these agents react with formation water ions to form inorganic salt gel precipitates, which physically block the flow, increasing the resistance of dominant channels and forcing the displacement fluid to flow towards low-permeability zones. However, this approach has significant drawbacks: the reaction distribution is uneven in heterogeneous reservoirs, resulting in large fluctuations in sealing efficiency; and the inorganic salt precipitates easily form scale in reservoir pores, causing irreversible damage to the formation.

[0003] Gel profile control performance is closely related to rheological properties. Polysaccharide-based polymers, due to their rigid three-dimensional network structure, exhibit superior loss modulus compared to linearly synthesized polymers. Sodium alginate (SA), a natural polysaccharide extracted from brown algae, is formed by glycosidic bonds linking β-D-mannuronic acid (M units) and α-L-guluronic acid (G units). It possesses advantages such as non-toxicity, low cost, wide availability, and biodegradability. Furthermore, its high molecular weight can increase the viscosity of the injection fluid, and its molecular chain rigidity meets the basic requirements for profile control. However, the gel strength formed by SA aqueous solution is weak, and it is easily destabilized by ion exchange in the reservoir environment, limiting its practical application. Meanwhile, SA combined with Ca²⁺... + The calcium alginate (CaAlg) gel formed, which uses an "egg box model" to pre-crosslink and fix calcium ions, can maintain long-term blocking under high mineralization and has become a research hotspot.

[0004] Common alginate gels are mainly prepared by introducing calcium ions into sodium alginate solution, using calcium chloride as the calcium source, and preparing the gel through direct mixing. However, this method still has shortcomings: ① Continuous injection of SA and Ca²⁺ +① The solution is prone to localized instantaneous cross-linking, forming heterogeneous gels and even causing near-wellbore blockage; ② The gel performance has not been optimized for environmental factors such as reservoir temperature and pH, and the gel network is prone to disintegration at high temperatures, with a significant decrease in cross-linking efficiency under acidic / alkaline environments; ③ The injection flow rate is mismatched with the cross-linking kinetics, affecting the sealing effect of the gel in deep high-permeability channels; ④ It has not been combined with efficient oil displacement technologies such as CO2 flooding—although CO2 flooding can improve fluidity by reducing viscosity (crude oil viscosity reduction of 30%~50%) and expanding crude oil (expansion rate of 5%~10%), due to cross-flow in high-permeability channels, the CO2 swept volume is only 40%~60% of the reservoir volume, limiting the displacement efficiency; at the same time, the carbonic acid generated by the reaction of CO2 with formation water will change the reservoir pH, which may destroy the cross-linking stability of traditional gels, resulting in the inability to coordinate profile control and CO2 flooding. Therefore, there is an urgent need to develop a CaAlg gel profile control technology that is compatible with CO2 flooding, directionally transported, and highly adaptable to the environment.

[0005] In the prior art, such as the water glass-calcium chloride two-liquid method disclosed in this application CN103834376A, although it can achieve plugging, the reaction is uncontrollable, which can easily cause near-wellbore blockage and cause great damage to the reservoir. Moreover, although it uses a sodium alginate gel system, it relies on calcium chloride as a calcium source, which leads to excessively fast cross-linking, making it impossible to achieve deep profile control, and it has poor stability in acidic, high temperature or CO2 environments. Summary of the Invention

[0006] To overcome the shortcomings of the existing technology, the present invention aims to provide a staged injection cross-linked calcium alginate gel profile control agent and method for heterogeneous reservoirs. This involves a cross-linking system composed of high-G sodium alginate (G / M=2) and 70 mmol / L calcium carbonate solution, with gluconolactone (GDL) added in the acidic reservoir (pH=3) to regulate Ca²⁺. + Sustained release; using "first inject Ca²" + The staged injection strategy of "SA injection after injection" enables in-situ cross-linking of gel in deep high-permeability channels, avoiding near-wellbore blockage. It can also be adaptively controlled for temperature, pH, and salinity, and can be used in conjunction with CO2 flooding technology. It is suitable for medium-low permeability reservoirs with high water cut and severe heterogeneity. Through the synergistic mechanism of "CaAlg gel directional blocking of high-permeability channels + CO2 flooding to improve crude oil fluidity", it solves the problems of difficult utilization of residual oil in low-permeability areas after traditional profile control agent blocking and severe cross-flow in CO2 flooding, thus achieving a high-efficiency improvement in oil recovery.

[0007] To achieve the above objectives, the technical solution adopted by the present invention is as follows: A staged injection crosslinked calcium alginate gel profile control agent for heterogeneous reservoirs, comprising a core crosslinking system and an optional sustained-release agent, wherein the core crosslinking system comprises a high-G sodium alginate (SA) solution at a concentration of 0.8 wt% to 1.0 wt% and 65 to 75 mmol / L Ca2+. 2+ The solutions were injected in a volume ratio of 1:1, wherein: The high-G type SA solution comprises guluronic acid G units and β-D-mannuronic acid M units, with a molar ratio of guluronic acid G units to β-D-mannuronic acid M units G / M = 1.8 ~ 2.2; The Ca 2+ The solution used is a 65-75 mmol / L calcium carbonate (CaCO3) solution or a CaCl2 solution; The sustained-release agent is gluconolactone (GDL). In an acidic reservoir environment with pH 2.8–3.2, the amount of sustained-release agent added is 0.5%–1.0% of the SA solution mass, used to regulate the gradual dissociation and release of Ca. 2+ Avoid SA and Ca 2+ Localized transient cross-linking occurs, forming a uniform calcium alginate (CaAlg) gel network with a pore size of 10 ~ 30 μm; The relationship between the dosage of the core crosslinking system and the slow-release agent is as follows: the slow-release agent is added only when the acidic reservoir environment has a pH of 2.8 to 3.2. When the slow-release agent is added, its mass is 0.5% to 1.0% of the SA solution mass in the core crosslinking system. During synergistic CO2 flooding, the slow-release agent mass is reduced to 0.3% to 0.8% of the SA solution mass. "Synergistic CO2 flooding" refers to the injection of CO2 after the CaAlg gel forms an effective seal, in a carbonate environment with a pH of 4 to 5 formed by the reaction of CO2 and formation water.

[0008] The profile control agent's temperature response: at a neutral room temperature environment (pH = 7), a high-G type SA solution with a concentration of 0.8 wt% ~ 1.0 wt% and 70 mmol / L Ca 2+ The complex shear modulus G* of CaAlg gel formed by in-situ cross-linking of the solution through the "egg box model" is ≥ 100 Pa. In a neutral, moderate temperature (50°C) environment, the G* value decreases by 30-40% compared to room temperature. + Diffusion accelerates, gelation time shortens, viscoelasticity becomes unbalanced, and the core cross-linking system enters the viscoelastic transition zone. The G* value drops to 30-40% of that at room temperature at a neutral 75°C, and the gel network gradually disintegrates and reconstructs. The cross-linked system of the same concentration showed a G* attenuation of more than 95% at 100°C compared to that at room temperature, and the CaAlg gel network completely decomposed at 100°C.

[0009] The profile control agent's pH response is as follows: under acidic conditions (pH = 3), the carboxyl-COOH group of the profile control agent binds H+. + Weakening the interaction between the carboxyl group -COOH and Ca² + Its coordination ability allows high-G type SA solutions at concentrations of 0.8 wt% and 1.0 wt% to react with 70 mmol / L Ca. 2+ The stability of the "egg-box structure" of the solution decreases; under acidic conditions (pH = 3), the pore size of the CaAlg gel network remains stable at 10 ~ 30 μm; in a neutral environment (pH = 7), the carboxyl-COOH groups of the profile control agent release H₂. + , with Ca² + Stable cross-linking is formed, with hydrogen bonds and ionic bonds working together to maintain the uniformity of the CaAlg gel network pore size (10 ~ 30 μm); while under alkaline conditions (pH = 10), OH... - Competition combined Ca² + This leads to the dissociation of ionic crosslinks, while simultaneously forming a high-density -COO in the profile control agent. - The increased electrostatic repulsion between chains causes the CaAlg gel network to disintegrate, hydrogen bonds to break, and the pore size to expand to 100 ~ 200 μm.

[0010] A method for staged injection profile control in heterogeneous reservoirs based on the aforementioned profile control agent includes the following steps: S1: Reservoir Pretreatment Stage For core / sand-filled tubes simulating the reservoir characteristics of actual heterogeneous oil reservoirs corresponding to the target heterogeneous oil reservoir, simulated formation water was saturated at a high pressure of 0.9~1.1MPa. The saturation simulation refers to injecting simulated formation water into the core / sand-filled tube under high pressure to completely fill its pores, simulating the original water-bearing state of the actual oil reservoir. Specifically, the core / sand-filled tube was placed in a core holder and a confining pressure of 0.9~1.1MPa was applied. Simulated formation water was injected at a flow rate of 0.18~0.22mL / min until water continuously flowed out of the outlet without air bubbles. The tube was allowed to stand for 22~26 hours to ensure sufficient saturation. Then, crude oil was injected into the inlet of the core / sand-filled tube at a flow rate of 0.18~0.22mL / min, with an injection volume of 1.2~1.5 times the pore volume of the core / sand-filled tube, to establish the original oil saturation. High-mineralized water with a salinity of 10000~20000mg / L was then injected to simulate a single water drive, with an injection volume of 8... ~12 times the pore volume, until the water phase ratio in the produced fluid extracted from the core / sand-filled pipe outlet is >90%, confirming the formation of the dominant seepage channel; S2: Stage I of graded injection, Ca² + Solution injection A 65–75 mmol / L CaCO3 solution was injected into the core / sand-filled tube at a flow rate of 0.18–0.22 mL / min, with an injection volume of 3–4 times the pore volume PV, to allow Ca to... 2+ Evenly distributed within the dominant channel; S3: Stage II of graded injection, SA solution is injected and cross-linked in situ to form CaAlg gel; After the first stage of staged injection is completed, maintain a flow rate of 0.18 ~ 0.22 mL / min and inject 0.8 ~ 1.0 wt% high G-type SA solution into the core / sand-filling tube; Under neutral reservoir conditions with pH = 6.5 ~ 7.5, SA and Ca injected in step S2 2+ Crosslinking via ion diffusion resulted in the formation of CaAlg gels in the 0.8 wt% SA system at 20–30 °C and an injection flow rate of 0.18–0.22 mL / min, with gelation rates of dG' / dt = 35–42 Pa / min. The same conditions resulted in the formation of gels in the 0.8–1.0 wt% SA system, with gelation rates of 3.5–4.5 min and dG' / dt = 48–52 Pa / min, achieving in-situ crosslinking. Under acidic reservoir conditions (pH 2.8–3.2), an SA solution containing GDL was injected. The SA concentration in the GDL-containing SA solution was 0.8–1.0 wt%, and the GDL addition amount was 0.5%–1.0% of the SA solution mass. GDL hydrolysis was used to regulate Ca2+ concentration. 2+ Slow release avoids instantaneous solidification, forming a gel with uniform pore size; achieves in-situ cross-linking to form CaAlg gel; S4: Subsequent Water Drive Phase III High-permeability channels are blocked using a "egg-box model" cross-linking network of CaAlg gel. After the CaAlg gel effectively blocks the high-permeability channels: the injection pressure in neutral reservoirs increases from the initial 0.4 MPa to 1.2 ~ 1.5 MPa, or in acidic reservoirs to 1.0 ~ 1.2 MPa, with a pressure fluctuation range of ≤5% for 5 consecutive minutes; high-mineralized water with a salinity of 10000 ~ 20000 mg / L is injected at a flow rate of 0.18 ~ 0.22 mL / min, forcing the displacing fluid to shift to the low-permeability zone. The low-permeability zone refers to the area in the heterogeneous reservoir where the permeability is lower than that of the high-permeability channels, with a permeability of 35 ~ 38 × 10⁻⁶. - ³μm², permeability of low-permeability zone: 10 ~ 20×10⁻⁶ - ³μm²; utilize the remaining oil in the low-permeability zone to complete the profile control operation.

[0011] A method for staged injection profile control in heterogeneous reservoirs based on the aforementioned profile control agent includes the following steps: S1: Reservoir Pretreatment Stage For core / sand-filled tubes simulating the reservoir characteristics of actual heterogeneous oil reservoirs corresponding to the target heterogeneous oil reservoir, simulated formation water was saturated at 1 MPa. The saturation simulation refers to injecting simulated formation water into the core / sand-filled tube under high pressure to completely fill its pores, simulating the original water-bearing state of the actual oil reservoir. Specifically, the core / sand-filled tube was placed in a core holder and a confining pressure of 1 MPa was applied. Simulated formation water was injected at a flow rate of 0.2 mL / min until water continuously flowed out of the outlet without air bubbles. The tube was allowed to stand for 24 hours to ensure sufficient saturation. Then, crude oil was injected into the inlet of the core / sand-filled tube at a flow rate of 0.42 mL / min, with the injection volume being 1.2 to 1.5 times the pore volume of the core / sand-filled tube, to establish the original oil saturation. High-mineralized water with a salinity of 10,000 to 20,000 mg / L was then injected to simulate a single water drive, with an injection volume of 8 to 10000 mg / L. 12 times the pore volume, until the water phase ratio in the produced fluid extracted from the core / sand-filled pipe outlet is >90%, confirming the formation of the dominant seepage channel; S2: Stage I of graded injection, Ca² + Solution injection A 70 mmol / L CaCO3 solution was injected into the core / sand-filled tube at a flow rate of 0.2 mL / min, with an injection volume of 3 to 4 times the pore volume PV, so that Ca... 2+ Evenly distributed within the dominant channel; S3: Stage II of graded injection, SA solution is injected and cross-linked in situ to form CaAlg gel; After the first stage of staged injection is completed, maintain a flow rate of 0.2 mL / min and inject 0.8 wt% and 1.0 wt% high G-type SA solution into the core / sand-filling tube; Under neutral reservoir conditions (pH=7), SA and Ca injected in step S2 2+ Crosslinking via ion diffusion resulted in the formation of CaAlg gels in 5 minutes at 20-30°C and an injection flow rate of 0.2 mL / min, with a gelation rate of dG' / dt = 38.21 Pa / min. In the same conditions, the 1.0 wt% SA system formed gels in 3 minutes, with a gelation rate of dG' / dt = 50.06 Pa / min, achieving in-situ crosslinking to form CaAlg gels. Under acidic reservoir conditions (pH=3), an SA solution containing GDL was injected. The SA concentration in the GDL-containing SA solution was 1.0 wt%, and the GDL addition amount was 0.5% ~ 1.0% of the SA solution mass. GDL hydrolysis regulated Ca2+. 2+ Slow release avoids instantaneous solidification, forming a gel with uniform pore size; achieves in-situ cross-linking to form CaAlg gel; S4: Subsequent Water Drive Phase III High-permeability channels are blocked using an "egg-box model" cross-linking network of CaAlg gel. After the CaAlg gel effectively blocks the high-permeability channels: the injection pressure in neutral reservoirs increases from the initial 0.4 MPa to 1.2 ~ 1.5 MPa, or in acidic reservoirs to 1.0 ~ 1.2 MPa, with a pressure fluctuation range of ≤5% for 5 consecutive minutes; high-mineralized water with a salinity of 10000 ~ 20000 mg / L is injected at a flow rate of 0.2 mL / min, forcing the displacing fluid to shift to the low-permeability zone. The low-permeability zone refers to the area in the heterogeneous reservoir where the permeability is lower than that of the high-permeability channels, with a permeability of 35 ~ 38 × 10⁻⁶. - ³μm², permeability of low-permeability zone: 10 ~ 20×10⁻⁶ - ³μm²; utilize the remaining oil in the low-permeability zone to complete the profile control operation.

[0012] In steps S2 to S4, SA solution and Ca 2+ The solution concentration is adaptively adjusted according to different reservoir temperatures: (1) When the reservoir temperature is ≤50℃, a solution of high-G sodium alginate (SA) with a concentration of 0.8wt% ~ 1.0wt% and 65~75mmol / L Ca is used. 2+ The core cross-linking system of the solution has an injection volume ratio of 1:1. (2) When the reservoir temperature is >50℃ and ≤75℃, the SA concentration is increased to 0.8 ~ 1.0wt% to compensate for the loss of gel strength caused by high temperature and ensure that the complex shear modulus G* of CaAlg gel is maintained at more than 30% ~ 40% under room temperature conditions.

[0013] The core / sand-filled tubes, before profile adjustment, had a length of 5.03–5.33 cm, a diameter of 2–3 cm, and a permeability of 13.15–17.78 × 10⁻⁶. - With a porosity of 13.92% to 18.65% and a diameter of 3 μm², it is suitable for medium-low permeability heterogeneous high water-cut oil reservoirs.

[0014] The core / sand-filled tube, after profile adjustment, has a length of 3-10 cm, a diameter of 2.5-5 cm, and a permeability of 13.15-17.78 × 10⁻⁶. - Core / sand-filled tubes with a porosity of 13.92% to 18.65% and a range of parameters, compatible with CO2 diffusion and displacement requirements.

[0015] When the profile control agent is used in conjunction with synergistic CO2 flooding, the timing of CO2 injection is after step S3 is completed. The CO2 injection method includes pure CO2 flooding or alternating CO2 and water flooding, wherein the slug volume ratio of alternating CO2 and water flooding is (CO2 slug: water slug) = (2~3):1.

[0016] Compared with the prior art, the present invention has the following beneficial effects: (1) Synergistic effect of plugging and oil displacement, significantly improving oil recovery: This invention adopts a synergistic scheme of "CaAlg gel directional plugging + CO2 oil displacement". In the core crosslinking system, high G-type SA (G / M=1.8~2.2) and 65~75mmol / L CaCO3 solution are injected in stages at a volume ratio of 1:1, forming a dense gel with a complex shear modulus G*≥100Pa in the neutral reservoir, with a plugging rate of 81.13%~87.56%; when synergistically CO2 is used for displacement (CO2-water alternating slug volume ratio 2~3:1), the viscosity reduction (30%~50% reduction in crude oil viscosity) and expansion (5%~10% expansion rate) effects of CO2 are utilized to promote the utilization of remaining oil in low-permeability areas, increasing the oil recovery rate from 15%~21% of single profile control to 22%~28%, which is far superior to traditional silicate profile control agents (oil recovery rate increase of only 8%~21%). 12%) and single CO2 drive (sweep volume only 40% ~ 60%).

[0017] (2) Avoiding the dual problems of near-wellbore blockage and CO2 crossflow: by "first Ca² + The staged injection technology of "solution (3~4PV) → post-SA solution (3~4PV)" avoids the local instantaneous cross-linking problem caused by traditional continuous injection; CaAlg gel solidifies in deep hyperpermeable channels (more than 40cm from the inlet) to form a uniform network with a pore size of 10~30μm, which not only blocks CO2 from flowing along the hyperpermeable channels, but also provides a stable seepage field for CO2 flooding, thus solving the technical contradiction between profile control and independent application of CO2 flooding.

[0018] (3) It has strong environmental adaptability and covers most medium- and low-permeability reservoir conditions: Temperature adaptation: Through concentration control scheme, the SA concentration in medium-temperature reservoirs of 50℃ ~ 75℃ can be increased to 0.8 ~ 1.0 wt% to compensate for the loss of gel strength and keep G at 30% ~ 40% of room temperature; when cooperating with CO2 flooding, CO2 can further reduce high-temperature damage and increase G to 45% ~ 55% of room temperature, adapting to the mainstream reservoir temperature of 25℃ ~ 75℃; pH adaptation: For acidic reservoirs (pH=2.8 ~ 3.2), adding 0.5% ~ 1.0% GDL can achieve Ca²⁺. +Slow-release, the neutral reservoir (pH=6.5 ~ 7.5) directly crosslinks to form a stable gel, and the carbonic acid environment generated by CO2 (pH=4 ~ 5) does not require additional adjustment, covering the acid-base range of pH=3 ~ 7; Mineralization adaptation: In reservoirs with high mineralization (>10000mg / L), CO2 can inhibit the destruction of gel network by ions, resulting in a reduction of ≤5% in the plugging rate and an improvement of 10% ~ 15% in stability compared to single profile control.

[0019] (4) Costs are controllable, and the economic benefits for industrial applications are outstanding: Reduced material costs: During CO2 flooding in acidic reservoirs, carbonic acid can help regulate Ca²⁺. + This release reduces the amount of GDL added by 20% to 40% (from 0.5% to 1.0% to 0.3% to 0.8%), thus reducing the consumption of the sustained-release agent; Dosage optimization: The oil displacement effect of CO2 reduces the total amount of profile control agent injected, decreasing the dosage by 15% to 20% compared to traditional single profile control agents; Environmentally friendly and low-cost: The core material SA is a natural polysaccharide (extracted from brown algae) that is biodegradable. CaCO3 is an inexpensive inorganic calcium source with no risk of formation pollution. The overall cost is 15% to 20% lower than that of traditional chemical profile control agents.

[0020] (5) Standardized process with strong repeatability and operability: The preparation of profile control agent (SA solution concentration 0.8~1.0wt%, CaCO3 solution 65~75mmol / L, GDL addition amount precisely quantified), injection process (flow rate 0.18~0.22mL / min, injection volume 3~4PV) and CO2 synergistic parameters (slug ratio 2~3:1, injection timing after gel plugging stabilization) are all standardized; 6 sets of core experiments (covering different temperatures and pH) verified that the coefficient of variation of core performance indicators (plugging rate, recovery rate increase) is ≤5%, which can directly guide the design of injection and production parameters in the mine and reduce on-site commissioning costs.

[0021] (6) Wide compatibility of calcium source and high flexibility of on-site construction: This invention supports two calcium sources, CaCO3 and CaCl2. CaCO3 is the preferred calcium source and CaCl2 is the alternative calcium source. The two have basically the same effect in reservoirs. On-site, the choice can be made flexibly according to whether CO2 flooding is carried out in the reservoir, the cost of calcium source procurement and the convenience of construction.

[0022] In summary, this invention has significant technical advantages and industrial application value, providing a new solution for the efficient development of heterogeneous high water-cut reservoirs. Attached Figure Description

[0023] Figure 1Diagram showing the source of sodium alginate and the synthesis mechanism of calcium alginate.

[0024] Figure 2 The graph shows the changes in G* for SA solutions with concentrations of 0.8% and 1.0% at different temperatures.

[0025] Figure 3 Electron micrographs of CaAlg under different pH conditions are shown; (a) pH=3, (b) pH=7, (c) pH=3 (Ca²⁺) + GDL), (d) pH=10.

[0026] Figure 4 The graph shows the changes in G* under different crosslinking systems and acid / alkaline conditions.

[0027] Figure 5 Pressure gradient of injected fluid flow at different flow rates ( P) and flow rate (Q) curves.

[0028] Figure 6 The two-phase relative permeability curves of the core are shown in Table 1.

[0029] Figure 7 The curves showing the core injection pressure variation are shown in Table 1. Detailed Implementation

[0030] The present invention will be further explained in detail below with reference to the embodiments and accompanying drawings.

[0031] A staged injection crosslinked calcium alginate gel profile control agent for heterogeneous reservoirs, comprising a core crosslinking system and a sustained-release agent, wherein the dosage relationship between the core crosslinking system and the sustained-release agent is as follows: Figure 1 This is a diagram illustrating the synthesis mechanism of calcium alginate. When a slow-release agent is added, its mass is 0.5%–1.0% of the SA solution mass in the core crosslinking system; during synergistic loading, the slow-release agent mass decreases to 0.3%–0.8% of the SA solution mass. The core cross-linking system comprises a 0.8wt%~1.0wt% high-G sodium alginate (SA) solution and 70 mmol / L Ca. 2+ The solutions were injected in a volume ratio of 1:1, wherein: The high-G type SA solution comprises guluronic acid G units and β-D-mannuronic acid M units, with a molar ratio of guluronic acid G units to β-D-mannuronic acid M units of G / M = 2. Ca 2+ The solution used is either a 70 mmol / L calcium carbonate (CaCO3) solution or a 70 mmol / L CaCl2 solution; The sustained-release agent is gluconolactone (GDL), added in an acidic reservoir environment at pH = 3, at a concentration of 0.5% to 1.0% of the SA solution mass, to regulate the gradual dissociation and release of Ca. 2+ Avoid SA and Ca 2+ Localized transient cross-linking occurs, forming a uniform calcium alginate (CaAlg) gel network with a pore size of 10~30 μm.

[0032] like Figure 2 At room temperature and a neutral pH of 7, a 1.0 wt% high-G type SA solution was reacted with 70 mmol / L Ca... 2+ The solution forms CaAlg gel through in-situ cross-linking using an "egg box model". The complex shear modulus G* of the CaAlg gel is ≥ 100 Pa. "Synergistic CO2 flooding" refers to the injection of CO2 after the CaAlg gel forms an effective seal, and the pH of the carbonate environment formed by the reaction of CO2 and formation water is 4~5.

[0033] A method for staged injection profile control in heterogeneous reservoirs based on the aforementioned profile control agent includes the following steps: S1: Reservoir Pretreatment Stage Experimental cores / sand-filled tubes simulating the reservoir characteristics of actual heterogeneous oil reservoirs were used to saturate simulated formation water under high pressure of 1 MPa. This saturation simulation refers to injecting simulated formation water into the core / sand-filled tube under high pressure to completely fill its pores, simulating the original water-bearing state of the actual oil reservoir. Specifically, the core / sand-filled tube was placed in a core holder, and a confining pressure of 1 MPa was applied. Simulated formation water was injected at a flow rate of 0.2 mL / min until water continuously flowed out of the outlet without air bubbles. The tube was then allowed to stand for 24 hours to ensure saturation. After sufficient injection, crude oil is injected into the inlet of the core / sand-filled pipe at a flow rate of 0.2 mL / min, with the injection volume being 1.2 to 1.5 times the pore volume of the core / sand-filled pipe, to establish the initial oil saturation. High-mineralized water with a salinity of 10,000 to 20,000 mg / L is then injected to simulate a single water drive, with the injection volume being 8 to 12 times the pore volume, until the water phase ratio in the produced fluid extracted from the outlet of the core / sand-filled pipe is >90%, confirming the formation of the dominant seepage channel. When the reservoir salinity is >10,000 mg / L, CO2 reduces the impact of high salinity on the stability of CaAlg gel, resulting in a gel plugging rate reduction of ≤5%, which is 10% to 15% higher than the plugging stability of single profile control.

[0034] S2: Stage I of graded injection, Ca² + Solution injection A 70 mmol / L CaCO3 solution was injected into the core of the heterogeneous reservoir at a flow rate of 0.2 mL / min, with an injection volume of 3–4 times the pore volume PV, to allow Ca to... 2+Uniformly distributed within the dominant channel; pressure gradient monitored during injection ( ), the p in and p out These are the inlet and outlet pressures, respectively. l For the flow length, ensure Ca² + Stable seepage of the solution; S3: Stage II of graded injection, SA solution injection and in-situ crosslinking to form CaAlg gel. After the first stage of staged injection is completed, a high-G type SA solution of 0.8–1.0 wt% is injected into the core of the heterogeneous reservoir at a flow rate of 0.2 mL / min. like Figure 3 and Figure 4 Under neutral reservoir conditions (pH=7), SA reacts with Ca injected in step S2. 2+ Crosslinking via ion diffusion resulted in the formation of CaAlg gels in 0.8 wt% SA system at 25 °C and an injection flow rate of 0.2 mL / min for 5 min. The gelation rate was dG' / dt = 38.21 Pa / min. In the same conditions, 1.0 wt% SA system formed gels in 4 min, with a dG' / dt = 50.06 Pa / min. This demonstrates the achievement of in-situ crosslinking to form CaAlg gels. Under acidic reservoir conditions (pH=3), an SA solution containing GDL was injected. The SA concentration in the GDL-containing SA solution was 1.0 wt%, and the GDL addition amount was 0.5%–1.0% of the SA solution mass. GDL hydrolysis regulated Ca2+. 2+ Slow release avoids instantaneous solidification, forming a gel with uniform pore size; achieves in-situ cross-linking to form CaAlg gel; In an alkaline reservoir environment with pH=10, OH - Competition combined Ca 2+ This leads to the dissociation of gel crosslinks, preventing the formation of an effective seal; S4: Subsequent Water Drive Phase III High-permeability channels, which are pore-throat networks in heterogeneous reservoirs with permeability many times higher than the surrounding areas, are blocked using a "egg-box model" cross-linked network of CaAlg gel. By blocking these high-permeability channels, the displacing fluid is forced to shift from high-permeability areas to low-permeability areas, covering more reservoir areas not affected by water flooding. Nuclear magnetic resonance (NMR) monitoring shows that the volume of displacing fluid swept by the fluid increases from 40%–50% in a single water flood to 70%–80%, and the utilization rate of remaining oil in low-permeability areas increases by 30%–40%. In synergistic CO2 flooding, the viscosity-reducing and crude oil expansion effects of CO2 are further utilized, resulting in a 30%–50% reduction in crude oil viscosity and a 5%–10% expansion, further improving the utilization efficiency of remaining oil in low-permeability areas. During synergistic CO2 flooding, this three-dimensional cross-linked network maintains a uniform structure with pore sizes of 10–30 μm even in a carbonated environment with pH 4–5. After the CaAlg gel effectively seals the high-permeability channels: the injection pressure in neutral reservoirs increases from the initial 0.4 MPa to 1.2~1.5 MPa or in acidic reservoirs to 1.0~1.2 MPa, with a pressure fluctuation of ≤5% for 5 consecutive minutes; high-mineralized water with a salinity of 10000~20000 mg / L is injected at a flow rate of 0.2 mL / min, forcing the displacing fluid to shift to the low-permeability zone. The low-permeability zone refers to the area in the heterogeneous reservoir where the permeability is lower than that of the high-permeability channels, with a permeability of 35~38 × 10⁻⁶. - ³μm², permeability of low-permeability zone 10~20×10 - ³μm²; utilize the remaining oil in the low-permeability zone to complete the profile control operation.

[0035] like Figure 5 In steps S2-S4, SA solution and Ca 2+ The injection flow rate of the solution and high-mineralized water was fixed at 0.2 mL / min to avoid inertial vortices that narrow the flow channel at flow rates ≥0.3 mL / min, or flow pattern changes that could lead to injection instability at flow rates ≤0.1 mL / min. Furthermore, the SA and Ca in the SA solution... 2+ Ca in solution 2+ The in-situ crosslinking efficiency and subsequent uniform diffusion of CO2 in porous media.

[0036] In steps S2 to S4, SA solution and Ca 2+ The solution concentration is adaptively adjusted according to different reservoir temperatures: (1) When the reservoir temperature is ≤50℃, a solution of high-G sodium alginate (SA) with a concentration of 0.8wt%~1.0wt% and 70mmol / L Ca is used. 2+ The core cross-linking system of the solution has an injection volume ratio of 1:1. (2) When the reservoir temperature is >50℃ and ≤75℃, the SA concentration is increased to 1.0wt% to compensate for the loss of gel strength caused by high temperature and to ensure that the complex shear modulus G* of CaAlg gel is maintained at more than 30%~40% under room temperature conditions. (3) When the reservoir temperature is >100℃, the CaAlg gel network is completely decomposed and G* decays by more than 95%, so this method is not applicable.

[0037] The heterogeneous reservoir cores have a length of 5.03–5.33 cm, a diameter of 2.5 cm, and a permeability of 13.15–17.78 × 10⁻⁶. - With a core diameter of 3 μm² and a porosity of 13.92%–18.65%, it is suitable for medium- to low-permeability heterogeneous high-water-cut reservoirs. In practical applications, the core dimensions can be adjusted according to the target reservoir thickness and permeability. After adjustment, the core length ranges from 3 to 10 cm, the diameter ranges from 2.5 to 5 cm, and the permeability needs to be maintained at 13.15–17.78 × 10⁻⁶. - ³μm², porosity needs to be maintained at 13.92%~18.65%; for synergistic CO2 flooding, the above-mentioned length 3~10cm, diameter 2.5~5cm, and permeability 13.15~17.78×10⁻⁶ μm², are required. - Core samples with a porosity of 13.92% to 18.65% (3 μm²) are shown in Table 1. These samples are compatible with CO2 diffusion and displacement requirements and require no additional restrictions. The relationship curves between the relative permeability of the oil and water phases and water saturation during water injection development are shown below. Figure 6 As shown in the figure, the dynamic graph of the staged injection pressure evolution over time is as follows: Figure 7 .

[0038] When the profile control agent is used in conjunction with synergistic CO2 flooding, the timing of CO2 injection is after step S3 is completed. The CO2 injection method includes pure CO2 flooding or alternating CO2 and water flooding, wherein the slug volume ratio of alternating CO2 and water flooding is (CO2 slug: water slug) = (2~3):1.

[0039] When the reservoir salinity is >10000mg / L, CO2 reduces the effect of high salinity on the stability of CaAlg gel, resulting in a gel plugging rate reduction of ≤5%, which is 10%~15% higher than the plugging stability of single profile control.

[0040] The heterogeneous reservoir is a high-water-cut reservoir (water cut > 90%) that has formed dominant seepage channels and enriched residual oil in low-permeability areas after long-term water flooding. The high-permeability channels can be blocked by the "egg-box structure" cross-linking network of CaAlg gel, thereby expanding the swept volume of the displacement fluid. If CO2 flooding is used in conjunction, CO2 can be further utilized to improve crude oil fluidity, enhance the utilization efficiency of residual oil in low-permeability areas, and improve the recovery rate.

[0041] The parameter ranges for all parameters of the heterogeneous reservoir are shown in Table 1, and the plugging rate calculation... kw1 and kw2 are the initial and final permeability values ​​of the core sample, respectively, in μm2. When combined with CO2 flooding, the plugging rate can be increased by 3% to 5% compared with profile control alone, and the recovery rate can be further increased.

[0042] Table 1. Core displacement experimental parameters (Examples 1-6) Note: The core displacement experiment parameters in Examples 7-9 are the same as those in Examples 1, 2, and 6, respectively.

[0043] When the profile control agent is used in conjunction with CO2 flooding, the timing of CO2 injection is after the CaAlg gel forms an effective seal (i.e., when step S3 of claim 3 ends and the injection pressure stabilizes to the peak value). The CO2 injection method includes pure CO2 flooding or CO2-water alternating flooding, wherein the slug volume ratio of CO2-water alternating flooding is (2~3):1 (CO2 slug: water slug).

[0044] In the CO2 flooding synergistic stage III, if the reservoir salinity is >10000mg / L, CO2 can reduce the effect of salinity on CaAlg gel, resulting in a gel plugging rate reduction of ≤5%, which improves the plugging rate stability by 10%~15% compared to single profile control.

[0045] To address the aforementioned issues, this invention proposes a core strategy of "staged injection - delayed crosslinking," constructing a technical solution from four aspects: profile control agent composition, preparation method, injection process, and environmental adaptability regulation. (1) Design of profile control agent composition Core crosslinking system: High-G type SA (G / M=2) is selected, with high G unit carboxyl group density, and it is compatible with Ca²⁺. + It exhibits excellent cross-linking efficiency and maintains the ionized state of carboxyl groups even in a carbonic acid environment (pH=4~5) where CO2 is generated; Ca² + Derived from a 70 mmol / L CaCO3 solution, it avoids calcium salts such as CaCl2 that are prone to causing transient cross-linking, and CaCO3 is compatible with carbonic acid without side reactions; the SA concentration is limited to 0.8 wt%~1.0 wt%. Low concentrations (<0.8 wt%) cannot form a stable gel, while high concentrations (>1.0 wt%) are prone to premature formation of weak gels, increasing pumping energy consumption, and this concentration range is compatible with the diffusion requirements of CO2.

[0046] Slow-release formulation adaptation (CO2 synergistic optimization): GDL is added in an acidic environment (pH=3) to regulate Ca² through slow hydrolysis. + Release rate; if co-driven with CO2, carbonic acid can help reduce reservoir pH, and the amount of GDL added can be reduced by 20%~40%, which reduces costs and avoids excessive gel brittleness caused by excessive GDL.

[0047] (2) Hierarchical injection process design Adopt "first Ca²" + The hierarchical synergistic model of "→SA→CO2": Stage I: Ca² injection + Solution, so that Ca² + The solution is evenly distributed within the dominant seepage channels to avoid direct mixing with SA and instantaneous cross-linking, while simultaneously laying the "blocking foundation" for CO2 drive; in stage II, SA solution is injected to react with the previously distributed Ca²⁺. + In-situ crosslinking within a porous medium, with precise control of gelation time (4-5 min), ensures gel solidification in deep, high-permeability channels (above 40 cm from the inlet), preventing near-wellbore blockage. If combined with CO2 flooding, the gel network formed in this stage can block CO2 crossflow. Stage III involves injecting CO2 (pure CO2 or alternating CO2-water), utilizing CO2's viscosity-reducing and expansion properties to drive the remaining oil in the low-permeability zone towards the production well. Simultaneously, the carbonic acid generated by CO2 helps maintain gel stability. The injection flow rate is 0.2 mL / min, balancing flow stability, crosslinking efficiency, and CO2 diffusion uniformity.

[0048] (3) Environmental Adaptive Regulation Temperature control: At medium temperatures (50℃~75℃), increase the SA concentration to 1.0wt% to compensate for gel strength loss; when synergistically driven by CO2, CO2 can reduce the damage to the gel caused by high temperatures, maintaining G* at 45%~55% in the room temperature group (higher than 30%~40% with single profile control); high temperatures (>100℃) are not applicable because the gel network completely decomposes, and CO2 accelerates this process. pH control: Neutral (pH=7) is the optimal environment, with sufficient deprotonation of carboxyl groups and stable crosslinking; acidic (pH=2.8~3.2) requires the addition of GDL (reduced when synergistically driven by CO2); alkaline (pH=10) is not applicable because OH... - Competition combined Ca² + This leads to gel dissociation, and CO2 cannot exist stably in an alkaline environment; the carbonic acid environment generated by CO2 (pH=4~5) is a compatible range and requires no additional adjustment. Mineralization control: In reservoirs with high mineralization (>10000mg / L), CO2 can reduce the influence of ions on the gel, resulting in a ≤5% reduction in the plugging rate, which improves stability compared to single profile control.

[0049] Example 1: 0.8% SA / Ca² + Application of the system in profile control of room temperature neutral reservoirs 1. Experimental parameters Core parameters: length 5.33cm, diameter 2.5cm, permeability 15.25×10⁻⁶. - ³μm², porosity 16.19% Profile control agent composition: 0.8wt% high-G type SA (G / M=2) solution + 70mmol / L CaCO3 solution (without sustained-release agent) Simulated reservoir conditions: temperature 25℃, pH=7 (neutral). 2. Experimental Procedure Reservoir pretreatment: The core was saturated with simulated formation water at a high pressure of 1 MPa and allowed to stand for 30 min to ensure full saturation. Then, crude oil was injected at a flow rate of 0.2 mL / min until no formation water flowed out of the core outlet, establishing the original oil saturation. High-mineralized water was injected to simulate primary water drive, and the water cut of the produced fluid was monitored until the water cut was >90% (at which point the relative permeability of the water phase Krw≈60%, and the dominant seepage channel was formed).

[0050] Stage I of graded injection (Ca²) + Solution injection: A 70 mmol / L CaCO3 solution was injected at a flow rate of 0.2 mL / min, with an injection volume of 4 times the pore volume (PV). During the injection process, the pressure was slowly increased from an initial 0.2 MPa to 0.4 MPa, indicating that Ca²⁺… + It is evenly distributed within the dominant seepage channels, with no local accumulation.

[0051] Stage II of staged injection (SA solution injection and in-situ crosslinking): After stage I, a 0.8 wt% high-G type SA solution was injected at a flow rate of 0.2 mL / min. According to the dynamic oscillation test results, the gel point appeared in this system in about 5 minutes, and the gel rate dG′ / dt≈38.21 Pa / min. After 5 minutes of injection, the core injection pressure started to rise from 0.4 MPa and stabilized at 1.2 MPa at 10 minutes, indicating that CaAlg gel effectively blocked the deep high-permeability channels.

[0052] Subsequent water flooding stage III: Continue to inject highly mineralized water at a rate of 0.2 mL / min, with the pressure fluctuating between 1.1 and 1.2 MPa. The displacing fluid shifts to the low-permeability zone, and the crude oil content in the produced fluid continues to increase until the water cut rises to 98% again, at which point the experiment is stopped.

[0053] 3. Experimental Results Blocking rate: 81.13% Recovery rate increase: 15.32% (compared to the final recovery rate of a single waterflooding operation) Key finding: 0.8% SA / Ca² + The system can form a stable gel in a neutral environment at room temperature, which can block high-permeability channels. However, the gelation rate is slow, requiring more than 5 minutes to form an effective plug. It is suitable for medium-low permeability neutral reservoirs where the plugging response speed is not critical.

[0054] Example 2: 1.0% SA / Ca² + Application of the system in profile control of room temperature neutral reservoirs 1. Experimental parameters Core parameters: length 5.16cm, diameter 2.5cm, permeability 14.63×10⁻⁶. - ³μm², porosity 13.92% Profile control agent composition: 1.0 wt% high-G type SA (G / M=2) solution + 70 mmol / L CaCO3 solution (without sustained-release agent) Simulated reservoir conditions: temperature 25℃, pH=7 (neutral). 2. Experimental Procedure Reservoir pretreatment: Same as in Example 1, one-time water flooding to water cut >90%, Krw≈60%.

[0055] Stage I of graded injection: Same as in Example 1, inject 4 PV of 70 mmol / L CaCO3 solution, and increase the pressure from 0.2 MPa to 0.45 MPa.

[0056] Stage II of graded injection: 1.0 wt% high-G type SA solution was injected. The gel point appeared in this system in about 4 min, and the gel rate dG′ / dt≈50.06 Pa / min. After 4 min of injection, the pressure rose rapidly and reached a peak of 1.5 MPa at 8 min. The density of the gel network was better than that in Example 1.

[0057] Subsequent water drive stage III: The pressure stabilized at 1.4~1.5MPa, the remaining oil in the low-permeability zone was fully utilized, and the peak crude oil content of the produced fluid was higher than that in Example 1.

[0058] 3. Experimental Results Plugging rate: 87.56% (the highest among 6 core samples) Recovery rate increase: 21.40% (optimal harvesting effect) Key conclusion: 1.0% SA / Ca² +The system exhibits rapid gelation rate and high network density under room temperature and neutral conditions, resulting in optimal plugging and oil displacement effects. This is the core preferred solution of the present invention and is applicable to most room temperature, neutral, low-to-medium permeability heterogeneous oil reservoirs.

[0059] Example 3: 0.8% SA / Ca² + Application of the system in profile control of intermediate-temperature neutral reservoirs 1. Experimental parameters Core parameters: length 5.03cm, diameter 2.5cm, permeability 17.78×10⁻⁶. - ³μm², porosity 18.65% Profile control agent composition: 0.8wt% high-G type SA solution + 70mmol / L CaCO3 solution (without sustained-release agent) Simulated reservoir conditions: temperature 75℃ (mesotropic), pH=7 (neutral). 2. Experimental Procedure Reservoir pretreatment: Simulated formation water and crude oil were both preheated to 75°C, and the remaining operations were the same as in Example 1, with one water drive to a water cut >90%.

[0060] Stage I: The CaCO3 solution is preheated to 75°C before injection, as the increased temperature accelerates the Ca²⁺ injection process. + Diffusion occurred, with pressure increasing from 0.2 MPa to 0.35 MPa (below room temperature).

[0061] Stage II of graded injection: 0.8wt% SA solution was injected. The gel network was easily disintegrated and reconstructed at high temperature. The time for gel point appearance was shortened to 4 min, but G* dropped to 30% of the room temperature group. After 4 min of injection, the pressure slowly increased and only reached 0.8 MPa at 10 min.

[0062] In the subsequent water flooding stage III, the pressure fluctuates greatly (0.7~0.8MPa), the gel stability is poor, and some gel fragments migrate with the water flooding.

[0063] 3. Experimental Results Blocking rate: 48.75% Recovery rate increase: 6.23% Key finding: 0.8% SA / Ca² + The gel strength of the system decreased significantly at a medium temperature of 75℃, resulting in a weak plugging effect. It is only suitable for medium-temperature reservoirs with low requirements for recovery rate increase and needs to be optimized by increasing the SA concentration.

[0064] Example 4: 1.0% SA / Ca² + Application of the system in profile control of intermediate-temperature neutral reservoirs 1. Experimental parameters Core parameters: length 5.12cm, diameter 2.5cm, permeability 13.15×10⁻⁶. - ³μm², porosity 16.33% Profile control agent composition: 1.0 wt% high-G type SA solution + 70 mmol / L CaCO3 solution (without sustained-release agent) Simulated reservoir conditions: temperature 75℃ (mesotropic), pH=7 (neutral). 2. Experimental Procedure Reservoir pretreatment: Same as in Example 3, simulated formation water and crude oil are preheated to 75°C, and water drive is performed once to achieve a water cut of >90%.

[0065] Stage I of graded injection: 4 PV of 70 mmol / L CaCO3 solution was injected, and the pressure was increased from 0.2 MPa to 0.4 MPa.

[0066] Stage II of graded injection: 1.0 wt% SA solution was injected to compensate for the loss of gel strength caused by high temperature by increasing the SA concentration. G* was maintained at 40% of the room temperature group, and the gel point appeared in about 3.5 min. After 3.5 min of injection, the pressure increased and stabilized at 1.0 MPa at 10 min (higher than in Example 3).

[0067] Subsequent water drive stage III: pressure fluctuations were smaller (0.9~1.0MPa), and gel stability was better than in Example 3.

[0068] 3. Experimental Results Blocking rate: 55.92% Recovery rate increase: 8.87% Key conclusion: 1.0% SA / Ca² + By increasing the SA concentration, the system can improve gel stability under mesophilic conditions, and its plugging and recovery effects are better than those of the 0.8% concentration system. It is suitable for mesophilic neutral reservoirs at around 75℃, but its effect is still lower than that of the room temperature group.

[0069] Example 5: 1.0% SA / Ca² + Application of the system in profile control of room temperature alkaline reservoirs 1. Experimental parameters Core parameters: length 5.19cm, diameter 2.5cm, permeability 17.36×10⁻⁶. - ³μm², porosity 14.16% Profile control agent composition: 1.0 wt% high-G type SA solution + 70 mmol / L CaCO3 solution (without sustained-release agent) Simulated reservoir conditions: temperature 25℃, pH=10 (alkaline). 2. Experimental Procedure Reservoir pretreatment: The simulated formation water was adjusted to pH=10 with NaOH, and the remaining operations were the same as in Example 1. One water drive was performed to bring the water cut to >90%.

[0070] Stage I of fractional injection: Injection of 4 PV of 70 mmol / L CaCO3 solution, Ca²⁺ under alkaline conditions. + With OH - The reaction produces Ca(OH)2 precipitate, which partially blocks the near-well pores, causing the pressure to rise rapidly from 0.2 MPa to 0.6 MPa (abnormally high).

[0071] Stage II of fractional injection: Injection of 1.0 wt% SA solution, OH under alkaline conditions. - Competition combined Ca² + Ions crosslink and dissociate, failing to form a stable gel; the injection pressure does not increase significantly throughout the process, remaining at 0.6~0.7MPa, with only localized loose aggregates forming.

[0072] In the subsequent water-drive stage III, the pressure rapidly dropped to 0.3 MPa, and the loose aggregates were dispersed by the water drive, resulting in no effective sealing effect.

[0073] 3. Experimental Results Blocking rate: 12.36% (almost no effective blocking) Recovery rate increase: 1.58% (close to no increase) Key conclusion: 1.0% SA / Ca² + The system, under alkaline conditions at pH=10, due to OH... - The cross-linking network is destroyed, making it impossible to form an effective gel, resulting in extremely poor sealing and harvesting effects. Therefore, the technical solution of this invention is not suitable for alkaline reservoirs.

[0074] Example 6: 1.0% SA / Ca² + Application of GDL system in profile control of room temperature acidic reservoirs 1. Experimental parameters Core parameters: length 5.31 cm, diameter 2.5 cm, permeability 16.29 × 10⁻⁶. - ³μm², porosity 15.29% Profile control agent composition: 1.0 wt% high-G type SA solution + 70 mmol / L CaCO3 solution + gluconolactone (GDL, sustained-release agent) Simulated reservoir conditions: temperature 25℃, pH=3 (acidic). 2. Experimental Procedure Reservoir pretreatment: The simulated formation water was adjusted to pH=3 with HCl, and the remaining operations were the same as in Example 1. One water drive was performed to bring the water cut to >90%.

[0075] Stage I: Injection of 4 PV of 70 mmol / L CaCO3 solution containing GDL, initial stable pH of GDL, and Ca²⁺. + The pressure was evenly distributed and slowly increased from 0.2 MPa to 0.4 MPa.

[0076] Stage II of staged injection: Injection of 1.0 wt% SA solution; GDL slowly hydrolyzes to gluconic acid under acidic conditions, regulating the gradual release of Ca²⁺ from CaCO₃. + This avoids localized instantaneous cross-linking; the gel point appears in about 4.5 min, and the gel rate dG′ / dt≈42.15 Pa / min; the pressure increases after 4.5 min of injection and stabilizes at 1.2 MPa after 10 min.

[0077] Subsequent water drive stage III: The pressure is maintained at 1.1~1.2MPa, the gel network pore size is uniform (10~30μm), and the remaining oil in the low-permeability zone is fully utilized.

[0078] Example 7: 0.8% SA / Ca² + Application of the system in profile control of room temperature neutral reservoirs 1. Experimental parameters Core parameters: length 5.33cm, diameter 2.5cm, permeability 15.25×10⁻⁶. - ³μm², porosity 16.19% Profile control agent composition: 0.8wt% high-G type SA (G / M=2) solution + 70mmol / L CaCl2 solution (without sustained-release agent) Simulated reservoir conditions: temperature 25℃, pH=7 (neutral). 2. Experimental Procedure Reservoir pretreatment: The core was saturated with simulated formation water at a high pressure of 1 MPa and allowed to stand for 30 min to ensure full saturation; then crude oil was injected at a flow rate of 0.2 mL / min until no formation water flowed out of the core outlet, establishing the original oil saturation; high-mineralized water was injected to simulate primary water drive, and the water cut of the produced fluid was monitored until the water cut was >90% (at which point the relative permeability of the water phase Krw≈62%, and the dominant seepage channel was formed).

[0079] Stage I of graded injection (Ca²) +Solution injection: 70 mmol / L CaCl2 solution was injected at a flow rate of 0.2 mL / min, with an injection volume of 4 times the pore volume (PV). During the injection process, the pressure was slowly increased from an initial 0.2 MPa to 0.4 MPa, indicating that Ca²⁺... + It is evenly distributed within the dominant seepage channels, with no local accumulation.

[0080] Stage II of staged injection (SA solution injection and in-situ crosslinking): After stage I, a 0.8 wt% high-G type SA solution was injected at a flow rate of 0.2 mL / min. According to the dynamic oscillation test results, the gel point appeared in this system in about 5 minutes, and the gel rate dG′ / dt≈38.18 Pa / min. After 5 minutes of injection, the core injection pressure started to rise from 0.4 MPa and stabilized at 1.2 MPa at 10 minutes, indicating that CaAlg gel effectively blocked the deep high-permeability channels.

[0081] Subsequent water flooding stage III: Continue to inject highly mineralized water at a rate of 0.2 mL / min, with the pressure fluctuating between 1.1 and 1.2 MPa. The displacing fluid shifts to the low-permeability zone, and the crude oil content in the produced fluid continues to increase until the water cut rises to 98% again, at which point the experiment is stopped.

[0082] 3. Experimental Results Blocking rate: 81.06% Recovery rate increase: 15.25% (compared to the final recovery rate of a single waterflooding operation) Key finding: 0.8% SA / Ca² + The system can form a stable gel in a neutral environment at room temperature, which can block high-permeability channels. However, the gelation rate is slow, requiring more than 5 minutes to form an effective plug. It is suitable for medium-low permeability neutral reservoirs where the plugging response speed is not critical.

[0083] Example 8: 1.0% SA / Ca² + Application of the system in profile control of room temperature neutral reservoirs 1. Experimental parameters Core parameters: length 5.16cm, diameter 2.5cm, permeability 14.63×10⁻⁶. - ³μm², porosity 13.92% Profile control agent composition: 1.0 wt% high-G type SA (G / M=2) solution + 70 mmol / L CaCl2 solution (without sustained-release agent) Simulated reservoir conditions: temperature 25℃, pH=7 (neutral). 2. Experimental Procedure Reservoir pretreatment: Consistent with Example 7, one-time water flooding to water cut >90%, Krw≈58%.

[0084] Stage I of graded injection: Same as in Example 1, inject 4 PV of 70 mmol / L CaCl2 solution, and increase the pressure from 0.2 MPa to 0.45 MPa.

[0085] Stage II of graded injection: 1.0 wt% high-G type SA solution was injected. The gel point appeared in this system in about 4 min, and the gel rate dG′ / dt≈49.98 Pa / min. After 4 min of injection, the pressure rose rapidly and reached a peak of 1.5 MPa at 8 min. The density of the gel network was better than that in Example 1.

[0086] Subsequent water drive stage III: The pressure stabilized at 1.4~1.5MPa, the remaining oil in the low-permeability zone was fully utilized, and the peak crude oil content of the produced fluid was higher than that in Example 1.

[0087] 3. Experimental Results Blocking rate: 87.48% (same as Example 2) Recovery rate increase: 21.32% (same as Example 2) Key conclusion: 1.0% SA / Ca² + The system exhibits rapid gelation rate and high network density under room temperature and neutral conditions, resulting in optimal plugging and oil displacement effects. This is the core preferred solution of the present invention and is applicable to most room temperature, neutral, low-to-medium permeability heterogeneous oil reservoirs.

[0088] Example 9: 1.0% SA / Ca² + Application of GDL system in profile control of room temperature acidic reservoirs 1. Experimental parameters Core parameters: length 5.31 cm, diameter 2.5 cm, permeability 16.29 × 10⁻⁶. - ³μm², porosity 15.29% Profile control agent composition: 1.0 wt% high-G type SA solution + 70 mmol / L CaCl2 solution + gluconolactone (GDL, sustained-release agent) Simulated reservoir conditions: temperature 25℃, pH=3 (acidic). 2. Experimental Procedure Reservoir pretreatment: The simulated formation water was adjusted to pH=3 with HCl, and the remaining operations were the same as in Example 1. One water drive was performed to bring the water cut to >90%.

[0089] Stage I: Injection of 4 PV of 70 mmol / L CaCl2 solution containing GDL, initial stable pH of GDL, and Ca²⁺.+ The pressure was evenly distributed and slowly increased from 0.2 MPa to 0.4 MPa.

[0090] Stage II of staged injection: Injection of 1.0 wt% SA solution; GDL slowly hydrolyzes to gluconic acid under acidic conditions, regulating the gradual release of Ca²⁺ from CaCl₂. + This avoids localized instantaneous cross-linking; the gel point appears in about 4.5 min, and the gel rate dG′ / dt≈42.15 Pa / min; the pressure increases after 4.5 min of injection and stabilizes at 1.2 MPa after 10 min.

[0091] Subsequent water drive stage III: The pressure is maintained at 1.1~1.2MPa, the gel network pore size is uniform (10~30μm), and the remaining oil in the low-permeability zone is fully utilized.

[0092] This invention utilizes "high-G type SA-Ca²" + The "core system + staged injection strategy + environmental adaptability control" approach solves the problems of near-wellbore blockage and poor environmental adaptability of traditional profile control agents. CaAlg gel achieves directional plugging of high-permeability channels through cross-linking via an "egg-box model," staged injection ensures gel solidification at depth, and GDL slow release and concentration adjustment expand its reservoir applicability. Experimental data show that this technology has high plugging efficiency and significantly improves recovery in low-to-medium permeability heterogeneous reservoirs, demonstrating significant industrial application value.

[0093] The embodiments provided above are not intended to limit the scope of the present invention, nor are the described steps intended to limit the order of their execution. Any obvious modifications made to the present invention by those skilled in the art in conjunction with existing common knowledge also fall within the scope of protection defined by the claims of the present invention.

Claims

1. A cross-linked calcium alginate gel profile control agent for staged injection in heterogeneous reservoirs, characterized in that, It includes a core cross-linking system and an optional sustained-release agent, wherein the core cross-linking system comprises a high-G sodium alginate (SA) solution at a concentration of 0.8 wt% to 1.0 wt% and 65 to 75 mmol / L Ca2+. 2+ The solutions were injected in a volume ratio of 1:1, wherein: The high-G type SA solution comprises guluronic acid G units and β-D-mannuronic acid M units, with a molar ratio of guluronic acid G units to β-D-mannuronic acid M units G / M = 1.8 ~ 2.2; The Ca 2+ The solution used is a 65-75 mmol / L calcium carbonate (CaCO3) solution or a CaCl2 solution; The sustained-release agent is gluconolactone (GDL). In an acidic reservoir environment with pH 2.8–3.2, the amount of sustained-release agent added is 0.5%–1.0% of the SA solution mass, used to regulate the gradual dissociation and release of Ca. 2+ Avoid SA and Ca 2+ Localized transient cross-linking occurs, forming a uniform calcium alginate (CaAlg) gel network with a pore size of 10 ~ 30 μm; The relationship between the core crosslinking system and the dosage of the slow-release agent is as follows: the slow-release agent is added only when the acidic reservoir environment has a pH of 2.8 to 3.

2. When the slow-release agent is added, its mass is 0.5% to 1.0% of the SA solution mass in the core crosslinking system. During synergistic CO2 flooding, the slow-release agent mass is reduced to 0.3% to 0.8% of the SA solution mass. "Synergistic CO2 flooding" refers to the injection of CO2 after the CaAlg gel forms an effective seal, in an environment with a pH of 4 to 5 formed by the reaction of CO2 and formation water.

2. The profile control agent according to claim 1, characterized in that, The profile control agent's temperature response: at a neutral room temperature environment (pH = 7), a high-G type SA solution with a concentration of 0.8 wt% ~ 1.0 wt% and 70 mmol / L Ca 2+ The complex shear modulus G* of CaAlg gel formed by in-situ cross-linking of the solution through the "egg box model" is ≥ 100 Pa. In a neutral, moderate temperature (50°C) environment, the G* value decreases by 30-40% compared to room temperature. + Diffusion accelerates, gelation time shortens, viscoelasticity becomes unbalanced, and the core cross-linking system enters the viscoelastic transition zone. The G* value drops to 30-40% of that at room temperature at a neutral 75°C, and the gel network gradually disintegrates and reconstructs. The cross-linked system of the same concentration showed a G* attenuation of more than 95% at 100°C compared to that at room temperature, and the CaAlg gel network completely decomposed at 100°C.

3. The profile control agent according to claim 1, characterized in that, The profile control agent's pH response is as follows: under acidic conditions (pH = 3), the carboxyl-COOH group of the profile control agent binds H+. + Weakening the interaction between the carboxyl group -COOH and Ca² + Its coordination ability allows high-G type SA solutions at concentrations of 0.8 wt% and 1.0 wt% to react with 70 mmol / L Ca. 2+ The stability of the "egg-box structure" of the solution decreased, and under acidic conditions (pH = 3), the pore size of the CaAlg gel network remained stable at 10 ~ 30 μm. In a neutral environment with pH = 7, the carboxyl-COOH group of the profile control agent releases H+. + , with Ca² + Stable cross-linking is formed, with hydrogen bonds and ionic bonds working together to maintain the uniformity of the CaAlg gel network pore size (10 ~ 30 μm); while under alkaline conditions (pH = 10), OH... - Competition combined Ca² + This leads to the dissociation of ionic crosslinks, while simultaneously forming a high-density -COO in the profile control agent. - The increased electrostatic repulsion between chains causes the CaAlg gel network to disintegrate, hydrogen bonds to break, and the pore size to expand to 100 ~ 200 μm.

4. A method for staged injection of profile control agents into heterogeneous reservoirs based on any one of claims 1 to 3, characterized in that, Includes the following steps: S1: Reservoir Pretreatment Stage For core / sand-filled tubes simulating the reservoir characteristics of actual heterogeneous oil reservoirs corresponding to the target heterogeneous oil reservoir, simulated formation water was saturated at a high pressure of 0.9~1.1MPa. The saturation simulation refers to injecting simulated formation water into the core / sand-filled tube under high pressure to completely fill its pores, simulating the original water-bearing state of the actual oil reservoir. Specifically, the core / sand-filled tube was placed in a core holder and a confining pressure of 0.9~1.1MPa was applied. Simulated formation water was injected at a flow rate of 0.18~0.22mL / min until water continuously flowed out of the outlet without air bubbles. The tube was allowed to stand for 22~26 hours to ensure sufficient saturation. Then, crude oil was injected into the inlet of the core / sand-filled tube at a flow rate of 0.18~0.22mL / min, with an injection volume of 1.2~1.5 times the pore volume of the core / sand-filled tube, to establish the original oil saturation. High-mineralized water with a salinity of 10000~20000mg / L was then injected to simulate a single water drive, with an injection volume of 8... ~12 times the pore volume, until the water phase ratio in the produced fluid extracted from the core / sand-filled pipe outlet is >90%, confirming the formation of the dominant seepage channel; S2: Stage I of graded injection, Ca² + Solution injection A 65–75 mmol / L CaCO3 solution was injected into the core / sand-filled tube at a flow rate of 0.18–0.22 mL / min, with an injection volume of 3–4 times the pore volume PV, to allow the CaCO3 solution to be injected. 2+ Evenly distributed within the dominant channel; S3: Stage II of graded injection, SA solution is injected and cross-linked in situ to form CaAlg gel; After the first stage of staged injection is completed, maintain a flow rate of 0.18 ~ 0.22 mL / min and inject 0.8 ~ 1.0 wt% high G-type SA solution into the core / sand-filling tube; Under neutral reservoir conditions with pH = 6.5 ~ 7.5, SA and Ca injected in step S2 2+ Through ion diffusion crosslinking, the 0.8wt%SA system formed gel points in 4.5 to 5 minutes at an injection flow rate of 0.18 to 0.22 mL / min at 20 to 30 °C, with a gelation rate of dG' / dt = 35 to 42 Pa / min; the 0.8 to 1.0wt%SA system formed gel points in 3.5 to 4.5 minutes under the same conditions, with a dG' / dt = 48 to 52 Pa / min, achieving in-situ crosslinking to form CaAlg gel; Under acidic reservoir conditions (pH 2.8–3.2), an SA solution containing GDL was injected. The SA concentration in the GDL-containing SA solution was 0.8–1.0 wt%, and the GDL addition amount was 0.5%–1.0% of the SA solution mass. GDL hydrolysis was used to regulate Ca2+ concentration. 2+ Slow release prevents instantaneous solidification, resulting in a gel with uniform pore size; Achieve in-situ crosslinking to form CaAlg gel; S4: Subsequent Water Drive Phase III High-permeability channels are blocked using an "egg-box model" cross-linking network of CaAlg gel. After the CaAlg gel effectively blocks the high-permeability channels: the injection pressure in neutral reservoirs increases from the initial 0.4 MPa to 1.2 ~ 1.5 MPa, or in acidic reservoirs to 1.0 ~ 1.2 MPa, with a pressure fluctuation range ≤ 5% for 5 consecutive minutes; high-mineralized water with a salinity of 10000 ~ 20000 mg / L is injected at a flow rate of 0.18 ~ 0.22 mL / min, forcing the displacing fluid to shift to the low-permeability zone. The low-permeability zone refers to the area in the heterogeneous reservoir where the permeability is lower than that of the high-permeability channels, with a permeability of 35 ~ 38 × 10⁻⁶. - ³μm², permeability of low-permeability zone: 10 ~ 20×10⁻⁶ - ³μm²; utilize the remaining oil in the low-permeability zone to complete the profile control operation.

5. The profile adjustment method according to claim 4, characterized in that, S1: Reservoir Pretreatment Stage For core / sand-filled tubes simulating the reservoir characteristics of actual heterogeneous oil reservoirs corresponding to the target heterogeneous oil reservoir, simulated formation water was saturated at 1 MPa. The saturation simulation refers to injecting simulated formation water into the core / sand-filled tube under high pressure to completely fill its pores, simulating the original water-bearing state of the actual oil reservoir. Specifically, the core / sand-filled tube was placed in a core holder and a confining pressure of 1 MPa was applied. Simulated formation water was injected at a flow rate of 0.2 mL / min until water continuously flowed out of the outlet without air bubbles. The tube was allowed to stand for 24 hours to ensure sufficient saturation. Then, crude oil was injected into the inlet of the core / sand-filled tube at a flow rate of 0.42 mL / min, with the injection volume being 1.2 to 1.5 times the pore volume of the core / sand-filled tube, to establish the original oil saturation. High-mineralized water with a salinity of 10,000 to 20,000 mg / L was then injected to simulate a single water drive, with an injection volume of 8 to 10000 mg / L. 12 times the pore volume, until the water phase ratio in the produced fluid extracted from the core / sand-filled pipe outlet is >90%, confirming the formation of the dominant seepage channel; S2: Stage I of graded injection, Ca² + Solution injection A 70 mmol / L CaCO3 solution was injected into the core / sand-filled tube at a flow rate of 0.2 mL / min, with an injection volume of 3 to 4 times the pore volume PV, so that Ca... 2+ Evenly distributed within the dominant channel; S3: Stage II of graded injection, SA solution is injected and cross-linked in situ to form CaAlg gel; After the first stage of staged injection is completed, maintain a flow rate of 0.2 mL / min and inject 0.8 wt% and 1.0 wt% high G type SA solution into the core / sand-filling tube; Under neutral reservoir conditions (pH=7), SA and Ca injected in step S2 2+ Crosslinking via ion diffusion resulted in the formation of CaAlg gels in 5 minutes at 20-30°C and an injection flow rate of 0.2 mL / min, with a gelation rate of dG' / dt = 38.21 Pa / min. In the same conditions, the 1.0 wt% SA system formed gels in 3 minutes, with a gelation rate of dG' / dt = 50.06 Pa / min, achieving in-situ crosslinking to form CaAlg gels. Under acidic reservoir conditions (pH=3), an SA solution containing GDL was injected. The SA concentration in the GDL-containing SA solution was 1.0 wt%, and the GDL addition amount was 0.5% ~ 1.0% of the SA solution mass. GDL hydrolysis regulated Ca2+. 2+ Slow release prevents instantaneous solidification, resulting in a gel with uniform pore size; Achieve in-situ crosslinking to form CaAlg gel; S4: Subsequent Water Drive Phase III High-permeability channels are blocked using an "egg-box model" cross-linking network of CaAlg gel. After the CaAlg gel effectively blocks the high-permeability channels: the injection pressure in neutral reservoirs increases from the initial 0.4 MPa to 1.2 ~ 1.5 MPa, or in acidic reservoirs to 1.0 ~ 1.2 MPa, with a pressure fluctuation range of ≤5% for 5 consecutive minutes; high-mineralized water with a salinity of 10000 ~ 20000 mg / L is injected at a flow rate of 0.2 mL / min, forcing the displacing fluid to shift to the low-permeability zone. The low-permeability zone refers to the area in the heterogeneous reservoir where the permeability is lower than that of the high-permeability channels, with a permeability of 35 ~ 38 × 10⁻⁶. - ³μm², permeability of low-permeability zone: 10 ~ 20×10⁻⁶ - ³μm²; utilize the remaining oil in the low-permeability zone to complete the profile control operation.

6. The profile adjustment method according to claim 4, characterized in that, In steps S2 to S4, SA solution and Ca 2 + The solution concentration is adaptively adjusted according to different reservoir temperatures: (1) When the reservoir temperature is ≤50℃, a solution of high-G sodium alginate (SA) with a concentration of 0.8wt% ~ 1.0wt% and 65~75mmol / L Ca is used. 2+ The core cross-linking system of the solution has an injection volume ratio of 1:

1. (2) When the reservoir temperature is >50℃ and ≤75℃, the SA concentration is increased to 0.8 ~ 1.0wt% to compensate for the loss of gel strength caused by high temperature and ensure that the complex shear modulus G* of CaAlg gel is maintained at more than 30% ~ 40% under room temperature conditions.

7. The profile adjustment method according to claim 4, characterized in that, The core / sand-filled tubes, before profile adjustment, had a length of 5.03–5.33 cm, a diameter of 2–3 cm, and a permeability of 13.15–17.78 × 10⁻⁶. - With a porosity of 13.92% to 18.65% and a diameter of 3 μm², it is suitable for medium-low permeability heterogeneous high water-cut reservoirs.

8. The profile adjustment method according to claim 7, characterized in that, The core / sand-filled tube, after profile adjustment, has a length of 3-10 cm, a diameter of 2.5-5 cm, and a permeability of 13.15-17.78×10⁻⁶. - Core / sand-filled tubes with a porosity of 13.92% to 18.65% and a range of parameters, compatible with CO2 diffusion and displacement requirements.

9. The profile adjustment method according to claim 4, characterized in that, When the profile control agent is used in conjunction with synergistic CO2 flooding, the timing of CO2 injection is after step S3 is completed. The CO2 injection method includes pure CO2 flooding or alternating CO2 and water flooding, wherein the slug volume ratio of alternating CO2 and water flooding is (CO2 slug: water slug) = (2~3):1.

Images