Carbonate fractured-vuggy reservoir optimized foam system and preparation and profile control and displacement method thereof

Abstract

The invention provides an optimized foam system for a fractured-vuggy carbonate reservoir as well as a preparation method and a profile control and displacement method thereof, and relates to the technical field of oilfield chemistry. The preparation method of the optimized foam system for the fractured-vuggy carbonate reservoir comprises the following steps: mixing a surfactant with a solution to obtain a surfactant solution; mixing the authigenic fiber with the obtained surfactant solution to obtain a solution; and the obtained solution and gas pass through a foam generator to generate foam. By means of the method, a stable packing layer with certain supporting capacity can be formed on the interface of the water layer and the foam to isolate subsequent foam from the water layer, the sweep range and the passing capacity of a foam system in a large-scale flowing space can be improved, and the sweep coefficient of the stratum is effectively improved.

Description

Technical Field

[0001] This invention relates to the field of oilfield chemistry, specifically to an optimized foam system for carbonate fractured-vuggy reservoirs, and its preparation and regulation methods. Background Technology

[0002] Carbonate reservoirs hold a crucial position in global oil and gas resources. Due to the severe heterogeneity of the reservoirs and the diversity of fracture and cavern connectivity patterns, waterflooding mechanisms are more complex. The final oil displacement effect and the distribution of remaining oil are controlled by the degree and extent of connectivity between large fractures and caverns within the cavern system. In the development of fracture-cavity carbonate reservoirs, foam systems are often required for conditioning and displacement.

[0003] Foam is a widely used flow control system in heterogeneous oil reservoir development. Due to its properties of water stability, oil defoaming, and increased plugging capacity with increasing permeability, foam flow control systems can effectively control mobility and mitigate cross-flow issues in heterogeneous formations. Furthermore, the relatively low gas density in foam can effectively enhance the utilization of the top oil layer. While foam can adjust the injection profile and improve oil recovery, it remains a thermodynamically unstable system. Foam stability remains the biggest obstacle to its application. As the foam travels further, the surfactant structure, solubility, aggregation behavior, and adsorption capacity at the gas / liquid surface change, all of which affect foam performance. Therefore, when foam flows in fractured-vuggy systems, the harsh formation conditions of high temperature and high salinity in fractured-vuggy reservoirs lead to a deterioration in overall foam flow performance. Simultaneously, when foam flows in fractured and cavernous media, gravitational differentiation causes significant stratification. The bursting foam releases liquid that mixes with formation water, resulting in the aqueous phase primarily flowing along the reservoir bottom during foam-driven flooding. The foam floating on the surface has high dryness and very weak fluidity, preventing effective flooding of the upper and middle parts of the reservoir. Therefore, existing foam systems are ineffective for highly permeable fractured and cavernous media.

[0004] Chinese patent CN116622359A discloses a self-assembled gel foam oil displacement agent and its preparation method suitable for high-temperature, high-salinity fractured-vuggy reservoirs, belonging to the field of oilfield chemical technology. The oil displacement agent comprises: 0.2-0.5% of a quaternary amphiphilic hydrophobic associative copolymer, 0.2-0.3% of a betaine Gemini surfactant, 0.1-0.35% of an amine oxide surfactant, 0.1-0.2% of a heat-resistant polyacid anhydride, 0.02-0.07% of a counterionic compound, 0.04-0.14% of a chelating agent, and the balance being water. The inorganic salt content in the water is 10-22%. The aforementioned raw materials are prepared into a foam oil displacement agent using a foam generator. The foam exhibits significantly improved stability after foaming. By improving the fluidity of the oil-water two-phase system, expanding the swept volume, significantly reducing the oil-water interfacial tension, increasing oil washing efficiency and formation energy, and enhancing the permeability of the oil phase liquid, the oil recovery rate of high-temperature, high-salinity fractured-vuggy reservoirs is significantly improved. However, the foam displacement agent formulation provided by this invention is complex to prepare and has a high cost.

[0005] Chinese patent CN111484838A discloses a composite plugging agent for carbonate fracture-vuggy reservoirs and its preparation method. The preparation method includes the following steps: (1) adding an anionic nonionic surfactant to water and stirring to obtain a surfactant solution; (2) passing the obtained surfactant solution and gas through a foam generator to generate foam after full contact; (3) adding rice husk ash to the generated foam and mixing thoroughly to obtain the composite plugging agent. The foam carrying the rice husk ash composite plugging agent prepared by the preparation method of this invention can effectively block high-permeability layers and improve oil recovery; at the same time, the composite plugging agent has a good blocking effect on both vertical heterogeneity and planar heterogeneity, effectively adjusting the water absorption profile of the formation, but it cannot be applied to high-temperature reservoirs.

[0006] Based on this, we developed an optimized foam system preparation method for carbonate fracture-vuggy reservoirs, which solves the problem of poor large-scale spatial sweep effect of existing foam systems and has high-temperature resistance, which is of great significance to researchers in this field. Summary of the Invention

[0007] To address the aforementioned problems, this invention provides a method for preparing and regulating a foam system for fractured-vuggy carbonate reservoirs. The method described in this invention can form a stable and supportive barrier layer at the water-foam interface, isolating subsequent foam from the water layer. This improves the sweep range and throughput of the foam system in a larger flow space, effectively increasing the formation sweep efficiency.

[0008] To achieve the above objectives, the technical solution adopted by the present invention is as follows:

[0009] On the one hand, this invention provides a method for preparing an optimized foam system for carbonate fractured-vuggy reservoirs, comprising the following steps:

[0010] S1: The surfactant is mixed with the solution to obtain a surfactant solution;

[0011] S2: The self-grown fibers are mixed with the surfactant solution obtained in S1 to obtain a solution;

[0012] S3: The solution and gas obtained from S2 pass through a foam generator to produce foam.

[0013] Preferably, in step S1, the surfactant is an anionic nonionic surfactant; more preferably, the surfactant is YF-1.

[0014] Preferably, in step S1, the concentration of the surfactant in the surfactant solution is 0.2%-1%; more preferably, in step S1, the concentration of the surfactant in the surfactant solution is 0.5%-1%.

[0015] Preferably, in step S1, the solution is formation water.

[0016] Preferably, in step S1, the mixing is stirring;

[0017] Preferably, the stirring temperature is 20-30℃, the stirring time is 1-2.5h, and the stirring rate is 400-600r / min. More preferably, the stirring temperature is 25-30℃, the stirring time is 1-2.0h, and the stirring rate is 500r / min.

[0018] Preferably, in step S2, the self-grown fibers are mixed with the surfactant solution obtained in S1 in 1-5 batches; more preferably, in step S2, the self-grown fibers are mixed with the surfactant solution obtained in S1 in 2-3 batches.

[0019] Preferably, in step S2, the concentration of autogenous fibers in the solution is 0.5%-5.5%; more preferably, in step S2, the concentration of autogenous fibers in the solution is 1%-5%.

[0020] Preferably, in step S2, the mixing is stirring;

[0021] Preferably, in step S2, the stirring operation is as follows: the self-grown fibers are added in batches to the surfactant solution obtained in S1 during stirring, the stirring temperature is 20-30℃, the stirring time is 3-6h, and the stirring rate is 400-600r / min; more preferably, the stirring temperature is 25-30℃, the stirring time is 4-6h, and the stirring rate is 500r / min.

[0022] Preferably, in step S3, the gas is nitrogen.

[0023] Preferably, in step S3, the mass of the foam is 60%-80%, and more preferably, in step S3, the mass of the foam is 68%-75%.

[0024] The mass of the foam is the percentage of gas volume to the total foam volume. Specifically, the mass of the foam can be expressed by the following formula:

[0025] Gas volume / total foam volume × 100%.

[0026] On the other hand, the present invention provides an optimized foam system for carbonate rock fracture-vuggy reservoirs prepared by the above-described preparation method.

[0027] Preferably, the optimized foam system for carbonate fractured-vuggy reservoirs is injected using slug injection. The volume of the first slug injection is 0.01PV-0.1PV. After shutting in the well for 0.5-1.5 hours, continuous slug injection continues, with the volume of the continuous slug injection being 0.1PV-0.4PV.

[0028] More preferably, the volume of foam injected into the first slug is 0.05PV-0.08PV, and after shutting in the well for 0.5-1.5 hours, foam is continuously injected into the slug, with the volume of foam injected into the slug being 0.2PV-0.35PV.

[0029] Furthermore, this invention provides a method for regulating and driving the optimized foam system of carbonate fractured-vuggy reservoirs prepared by the above-mentioned method, specifically as follows:

[0030] Drill wells at the top of the reservoir as injection wells and wells at the bottom as production wells. Inject a pre-generated foam from a slug into the injection well, shut in the well for 0.5-1.5 hours, and continue injecting foam continuously.

[0031] Preferably, the injection well is a vertical well;

[0032] Preferably, the production well is a horizontal well or a vertical well;

[0033] Preferably, the production well is located in the oil-water transition zone.

[0034] Compared with the prior art, the present invention has the following beneficial effects:

[0035] This invention addresses the problem of severe differentiation and poor large-scale spatial sweepability of foam systems in existing carbonate fractured-vuggy reservoirs. It proposes an optimized foam system preparation and regulation method based on a temperature- and salt-resistant foam system for ordinary carbonate fractured-vuggy reservoirs. The method described in this invention can form a stable and supportive sealing layer at the water-foam interface, isolating subsequent foam from the water layer. This improves the sweep range and throughput of the foam system in a larger-scale flow space, effectively increasing the formation sweepability coefficient. Detailed Implementation

[0036] To make the technical means, creative features, achieved objectives, and effects of this invention readily understandable, the invention is further illustrated below with specific embodiments. However, these embodiments are merely preferred embodiments and not all embodiments. Other embodiments obtained by those skilled in the art based on the embodiments described herein without creative effort are all within the scope of protection of this invention. It is worth noting that the raw materials used in this invention are all common commercially available products, and their sources are not specifically limited. The technical and scientific terms used in the embodiments have the meanings commonly understood by those skilled in the art to which this invention pertains.

[0037] Example 1

[0038] An optimized foam system for carbonate fractured-vuggy reservoirs, the preparation method of which includes the following steps:

[0039] S1: Surfactant YF-1 and formation water are stirred at 25℃-30℃ for 1-2 hours at a stirring rate of 500r / min to obtain a surfactant solution, wherein the concentration of surfactant YF-1 is 0.5%-1%;

[0040] S2: The self-grown fibers are mixed in two batches with the surfactant solution obtained from S1, which is being stirred. The mixture is stirred at 25℃-30℃ for 4-6 hours to fully dissolve the self-grown fibers, resulting in a solution with a concentration of 1%-5% for the self-grown fibers.

[0041] S3: The solution obtained from S2 is mixed with nitrogen gas and passed through a foam generator to produce foam, with the mass of the foam being 68%-75%.

[0042] An optimized foam system for regulation and displacement of carbonate fractured-vuggy reservoirs:

[0043] Drill wells at the top of the reservoir as injection wells and wells in the lower part as production wells. Inject a pre-generated foam from a slug into the injection well, controlling the injected foam volume to 0.05PV-0.08PV. Shut down the well for 0.5-1h and continue injecting foam, controlling the injected foam volume to 0.2PV-0.35PV. The self-generated fibers in the foam come into contact with the formation water to form an insoluble self-generated fiber hydrogel isolation layer, which supports the flow of subsequent injected foam and achieves the effect of increasing the sweep efficiency.

[0044] The injection well is a vertical well.

[0045] The production well is either a horizontal or vertical well, and is located in the oil-water transition zone.

[0046] Comparative Example 1

[0047] An optimized foam system for carbonate fractured-vuggy reservoirs, the preparation method of which includes the following steps:

[0048] Compared with Example 1, the only difference is that the surfactant in step S1 is changed to the anionic nonionic surfactant XHY-4.

[0049] The remaining operations are the same as in Example 1.

[0050] Comparative Example 2

[0051] An optimized foam system for carbonate fractured-vuggy reservoirs, the preparation method of which includes the following steps:

[0052] Compared with Example 1, the only difference is that in step S2, the self-grown fibers are replaced with nano-SiO2 particles.

[0053] The remaining operations are the same as in Example 1.

[0054] Comparative Example 3

[0055] An optimized foam system for carbonate fractured-vuggy reservoirs, the preparation method of which includes the following steps:

[0056] Compared with Example 1, the only difference is that the self-grown fibers in step S2 are replaced with fly ash particles.

[0057] The remaining operations are the same as in Example 1.

[0058] Comparative Example 4

[0059] An optimized foam system for carbonate fractured-vuggy reservoirs, the preparation method of which includes the following steps:

[0060] Compared to Example 1, only the concentration of the surfactant in step S1 was changed to 0.1%.

[0061] The remaining operations are the same as in Example 1.

[0062] Comparative Example 5

[0063] An optimized foam system for carbonate fractured-vuggy reservoirs, the preparation method of which includes the following steps:

[0064] Compared to Example 1, only the concentration of autogenous fibers in step S2 was changed to 0.5%.

[0065] The remaining operations are the same as in Example 1.

[0066] Comparative Example 6

[0067] An optimized foam system for carbonate fractured-vuggy reservoirs, the preparation method of which includes the following steps:

[0068] Compared to Example 1, only the concentration of autogenous fibers in step S2 was changed to 6%.

[0069] The remaining operations are the same as in Example 1.

[0070] Test Example 1

[0071] The foam generated in Example 1 and Comparative Examples 1-6 was injected into a sealed, visualized container filled with formation water. The container was then placed in a 130°C oven and heated until the foam volume was reduced by half. The foam half-life was then recorded.

[0072] Test Example 2

[0073] The enhanced oil recovery performance of the foam systems prepared in Example 1 and Comparative Examples 1-6 was evaluated, with the experimental temperature maintained at 130°C. The specific steps are as follows:

[0074] (1) Place the saturated oil fracture core in the core holder, perform an air tightness test, and keep the confining pressure about 5 MPa higher than the injection pressure.

[0075] (2) Inject formation water into the core at a rate of 1 mL / min until the pressure difference between the two ends of the core stabilizes, and record the stage oil production.

[0076] (3) The foam prepared in Example 1 was injected into the core at a rate of 0.2 mL / min, with an injection volume of 0.5 PV.

[0077] (4) Close the inlet and outlet of the clamp, wait for 1 hour for the self-generated fibers to fully gel, and then continue to inject foam at a rate of 1 mL / min, with an injection volume of 2 PV, and record the oil production at each stage.

[0078] The foam system exhibits good temperature resistance. After injecting the foam system into the fractured core, the recovery rate increased from 20.3% to 67.8%, effectively expanding the sweep efficiency and improving the recovery rate.

[0079] Table 1. Data of the foam systems in Example 1 and Comparative Examples 1-6

[0080]

[0081]

[0082] This invention improves upon conventional temperature- and salt-resistant surfactant systems for fractured-vuggy carbonate reservoirs. Adding self-grown fibers creates an insoluble, rigid, natural polymer gel barrier layer on the water-bearing surface without affecting foam properties or profile control capabilities. This barrier isolates formation water from subsequently injected foam, mitigating the reduced flow and oil-washing capacity caused by increased dryness due to gas-liquid separation. Under the same environmental conditions, it increases the effective reach of the foam, washing out residual oil from previously unreached areas. Therefore, this optimized foam system offers higher enhanced oil recovery capabilities than conventional foam systems.

[0083] Finally, it should be noted that the above content is only used to illustrate the technical solution of the present invention, and is not intended to limit the scope of protection of the present invention. Simple modifications or equivalent substitutions made by those skilled in the art to the technical solution of the present invention do not depart from the essence and scope of the technical solution of the present invention.

Claims

1. A method for preparing an optimized foam system for carbonate fracture-vuggy reservoirs, characterized in that, Includes the following steps: S1: The surfactant is mixed with the solution to obtain a surfactant solution; S2: The self-grown fibers are mixed with the surfactant solution obtained in S1 to obtain a solution; S3: The solution and gas obtained from S2 pass through a foam generator to produce foam.

2. The preparation method according to claim 1, characterized in that, In step S1, the surfactant is an anionic nonionic surfactant.

3. The preparation method according to claim 2, characterized in that, The anionic nonionic surfactant is YF-1.

4. The preparation method according to claim 1, characterized in that, In step S1, the concentration of the surfactant in the surfactant solution is 0.2%-1%.

5. The preparation method according to claim 4, characterized in that, In step S1, the concentration of the surfactant in the surfactant solution is 0.5%-1%.

6. The preparation method according to claim 1, characterized in that, In step S1, the mixing is stirring; the stirring temperature is 20-30℃, the stirring time is 1-2.5h, and the stirring rate is 400-600r / min.

7. The preparation method according to claim 1, characterized in that, In step S2, the concentration of autogenous fibers in the solution is 0.5%-5.5%.

8. The preparation method according to claim 7, characterized in that, In step S2, the concentration of autogenous fibers in the solution is 1%-5%.

9. The preparation method according to claim 1, characterized in that, In step S2, the mixing is stirring; the specific operation of stirring is as follows: the self-grown fibers are added in batches to the surfactant solution obtained in step S1, the stirring temperature is 20-30℃, the stirring time is 3-6h, and the stirring rate is 400-600r / min.

10. The preparation method according to claim 1, characterized in that, In step S3, the gas is nitrogen.

11. The preparation method according to claim 1, characterized in that, In step S3, the mass of the foam is 60%-80%.

12. The preparation method according to claim 11, characterized in that, In step S3, the mass of the foam is 68%-75%.

13. The optimized foam system for carbonate rock fracture-vuggy reservoirs prepared by the preparation method according to any one of claims 1-12.

14. The optimized foam system for carbonate fractured-vuggy reservoirs according to claim 13, characterized in that, The optimized foam system for carbonate fractured-vuggy reservoirs uses slug injection. The first slug injection foam volume is 0.01PV-0.1PV. After shutting in the well for 0.5-1.5 hours, continuous slug injection foam continues, with a continuous slug injection foam volume of 0.1PV-0.4PV.

15. The optimized foam system for carbonate fractured-vuggy reservoirs according to claim 14, characterized in that, The initial slug injection foam volume is 0.05PV-0.08PV. After shutting in the well for 0.5-1.5 hours, continuous slug injection foam is continued, with a continuous slug injection foam volume of 0.2PV-0.35PV.

16. A method for regulating and driving the optimized foam system for carbonate fractured-vuggy reservoirs prepared by the preparation method according to any one of claims 1-12, specifically comprising: Drill wells at the top of the reservoir as injection wells and wells at the bottom as production wells. Inject a pre-generated foam from a slug into the injection well, shut in the well for 0.5-1.5 hours, and continue injecting foam continuously.

17. The driving method according to claim 16, characterized in that, The injection well is a vertical well; the production well is a horizontal well or a vertical well.

18. The driving method according to claim 16, characterized in that, The production well is located in the oil-water transition zone.

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