Heterogeneous composite flooding system and its application and flooding method

Abstract

The present invention relates to the field of oil and gas field development, and discloses a heterogeneous composite oil recovery system, its application and oil recovery method. The heterogeneous composite oil recovery system includes: a gas phase in a gaseous state under underground oil reservoir conditions, a liquid phase in a liquid state under underground oil reservoir conditions, and a solid phase in a solid state under underground oil reservoir conditions; wherein the volume ratio of the gas phase to the liquid phase is 1:4-4:1; the solid phase includes a soft solid phase and a hard solid phase, and the weight ratio of the soft solid phase to the hard solid phase is 10:1-1:10. The heterogeneous composite oil recovery system of the present invention can be used in oil production. The heterogeneous composite oil recovery system of the present invention can form multiphase interfaces such as gas / liquid interface, gas / solid interface, liquid / solid interface, gas / liquid / solid interface, etc., can better match the pores of the oil reservoir, and the formed seepage resistance is significantly greater than that of a single heterogeneous composite oil recovery system, which can better expand the sweep coefficient and improve the recovery rate.

Description

Technical Field

[0001] The present invention relates to the field of oil and gas field development, and in particular to a heterogeneous composite oil displacement system and its application and oil displacement method. Background Art

[0002] At present, oil displacement systems can be divided into two categories: one is the homogeneous system, including polymers, binary composite flooding systems, and ternary composite flooding systems. It mainly achieves the purpose of expanding the sweep coefficient and improving the oil washing efficiency by adding chemicals to the water phase, which dissolves in the water phase and changes the properties of the water phase, thereby improving the recovery rate; the second is the heterogeneous system, which mainly adds a discontinuous phase to the continuous phase, utilizes the capillary force formed by the interface between the phases, increases the seepage resistance, and achieves the purpose of expanding the sweep coefficient. Surfactants can also be added in synergistically to reduce interfacial tension and improve oil washing efficiency, thereby greatly improving the recovery rate.

[0003] Viscoelastic particle flooding agent is a new type of granular oil displacement agent with a unique molecular structure of "partial cross-linking and partial branching". The heterogeneous chemical oil flooding method constructed based on viscoelastic particle flooding agent provides an effective way to significantly improve the recovery rate of high water content, high recovery degree and strong heterogeneous oil reservoirs. It is another new and internationally leading technological innovation after polymer flooding, ternary composite flooding and binary composite flooding, and has far-reaching strategic significance for the sustained and stable production of old oil fields.

[0004] Prior art discloses a heterogeneous composite flooding system consisting of a polymer, a viscoelastic particle flooding agent (B-PPG), and a surfactant (Sun Huanquan, "Post-Polymer Flooding Well Pattern Adjustment and Pilot Test Scheme for Heterogeneous Composite Flooding and Field Application" [J], Oil and Gas Geology and Recovery, 2014). Application of this system can increase oil recovery by 13.6%. Prior art also discloses a heterogeneous composite flooding system consisting of a viscoelastic particle flooding agent (PPG), a polymer, and a surfactant (Cui Xiaohong, "New Heterogeneous Composite Flooding Method" [J], Acta Petrolei Sinica, 2011). This system has a stronger sweep expansion capability than polymer flooding and similar oil washing capacity as composite flooding. Under the high-temperature, high-salinity, and post-polymer flooding conditions of Shengli Oilfield, it achieved better displacement results than polymer flooding and binary composite flooding. To achieve effective sweep efficiency and enhanced oil recovery, the aforementioned heterogeneous system, composed of both liquid and solid phases, requires the solid phase to possess excellent deformation, migration, and permeability. This requires that, under a specific displacement pressure differential, viscoelastic solid particles of a specific size be able to deform and pass through pore throats of a specific size, thereby migrating to the deeper reservoir, exerting their blocking and regulating effects, expanding sweep efficiency, and improving reservoir recovery. Therefore, the key to ensuring effective oil recovery lies in accurately optimizing the viscoelastic solid particle size and matching it with the pore throat size. However, field experience indicates that achieving this precise match is extremely difficult, if not impossible, primarily due to the highly heterogeneous distribution of pore throat sizes in reservoirs. Methods for effectively selecting viscoelastic particle displacement agents for target reservoirs are still underdeveloped, making it difficult to determine the viscoelastic solid particle size. Therefore, optimization of heterogeneous composite flooding systems is necessary. Summary of the Invention

[0005] The purpose of the present invention is to overcome the problem that the gas-liquid heterogeneous system or liquid-solid heterogeneous system in the prior art cannot significantly improve the recovery rate, and to provide a heterogeneous composite oil displacement system and its application and oil displacement method. The injection of this system can significantly expand the sweep coefficient and significantly improve the recovery rate.

[0006] In order to achieve the above-mentioned objectives, the first aspect of the present invention provides a heterogeneous composite oil recovery system, which includes: a gas phase in a gaseous state under underground oil reservoir conditions, a liquid phase in a liquid state under underground oil reservoir conditions, and a solid phase in a solid state under underground oil reservoir conditions; wherein the volume ratio of the gas phase to the liquid phase is 1:4-4:1; the solid phase includes a soft solid phase and a hard solid phase, and the weight ratio of the soft solid phase to the hard solid phase is 10:1-1:10.

[0007] The second aspect of the present invention provides the application of the aforementioned heterogeneous composite oil recovery system in oil production.

[0008] A third aspect of the present invention provides an oil recovery method, which comprises: injecting the aforementioned heterogeneous composite oil recovery system into a target oil reservoir to form a multiphase composed of a gas / solid interface, a gas / liquid interface, a liquid / solid interface and a gas / liquid / solid interface in the target oil reservoir.

[0009] Through the above technical solution, the beneficial technical effects achieved by the present invention are as follows:

[0010] 1. The heterogeneous composite flooding system of the present invention can form multiphase interfaces such as gas / solid interface, gas / liquid interface, liquid / solid interface, and gas / liquid / solid interface. When the heterogeneous composite flooding system of the present invention is injected, gas-liquid, liquid-solid, and gas-solid interfaces exist in the pores. At this time, the seepage resistance is approximately twice the capillary force of gas-liquid, gas-solid, liquid-solid, and gas-liquid-solid multiphases. The seepage resistance is significantly greater than that of a single heterogeneous composite flooding system, which can better expand the sweep coefficient and improve the recovery rate.

[0011] 2. When the heterogeneous composite flooding system of the present invention passes through pore throats, the presence of the phase interface creates additional capillary resistance, increasing the seepage resistance of the injected medium. This can significantly expand the sweep coefficient and improve the recovery rate. Taking the liquid-solid heterogeneous composite flooding system as an example, when solid particles pass through rock pores, a liquid-solid interface forms at both ends of the solid phase, creating additional capillary resistance. Only when the injection pressure exceeds the additional capillary resistance at both ends can the solid phase deform and pass through the pore throat. At this time, the seepage resistance is approximately twice the capillary force of the liquid-solid two-phase, resulting in a relatively large seepage resistance.

[0012] 3. The heterogeneous composite flooding system of the present invention includes a gas phase, a liquid phase, a soft solid phase, and a hard solid phase. Compared with the solid phase and the liquid phase, the gas phase has better elasticity and stronger deformation ability. During the injection process, on the one hand, part of the gas phase can adhere to the surface of the solid phase, which is equivalent to putting "soft clothes" on the solid phase, ensuring that the solid phase has good elasticity and can achieve good deformation and permeability; on the other hand, part of the gas phase and the solid phase migrate in coordination, which is equivalent to adding a "sponge cushion" to the solid phase. The above two aspects have greatly increased the elasticity of the solid phase. When screening viscoelastic solid phase particles, the size range of the optional particles becomes larger, which is conducive to on-site implementation and guarantees the effect of improving oil reservoir recovery. DETAILED DESCRIPTION

[0013] The endpoints of the ranges and any values ​​disclosed herein are not limited to the precise ranges or values, and these ranges or values ​​should be understood to include values ​​close to these ranges or values. For numerical ranges, the endpoints of each range, the endpoints of each range and individual point values, and the individual point values ​​can be combined with each other to obtain one or more new numerical ranges, which should be considered to be specifically disclosed herein.

[0014] A first aspect of the present invention provides a heterogeneous composite oil recovery system, which includes: a gas phase in a gaseous state under underground oil reservoir conditions, a liquid phase in a liquid state under underground oil reservoir conditions, and a solid phase in a solid state under underground oil reservoir conditions; wherein the volume ratio of the gas phase to the liquid phase is 1:4-4:1; the solid phase includes a soft solid phase and a hard solid phase, and the weight ratio of the soft solid phase to the hard solid phase is 10:1-1:10.

[0015] In the present invention, as the soft solid phase increases, it can deform and pass through pore throats, facilitating the sealing of deep reservoirs. As the hard solid phase increases, it has a better sealing effect on extreme reservoirs (where sand production leads to severe underground depletion). The solid phase includes a soft solid phase and a hard solid phase. The soft solid phase is optimized based on elastic modulus and particle size, while the hard solid phase is optimized based on particle size.

[0016] The heterogeneous composite flooding system of the present invention can form multiphase interfaces such as gas / liquid interface, gas / solid interface, liquid / solid interface, and gas / liquid / solid interface, which can significantly increase seepage resistance and expand the swept volume. When the heterogeneous composite flooding system passes through the pore throat, due to the presence of the phase interface, additional capillary resistance is formed, which increases the seepage resistance of the injected medium, can significantly expand the sweep coefficient and improve the recovery rate. Taking the liquid-solid heterogeneous composite flooding system as an example, when solid particles pass through the rock pores, liquid-solid interfaces are formed at both ends of the solid phase, thereby forming additional capillary resistance. Only when the injection pressure is greater than the additional capillary resistance at both ends can the solid phase deform and pass through the pore throat. At this time, the seepage resistance is approximately twice the capillary force of the liquid and solid phases, and the seepage resistance is relatively large.

[0017] According to the design of the present invention, when a heterogeneous composite flooding system is injected, gas-liquid, liquid-solid, and gas-solid interfaces exist in the pores. At this time, the seepage resistance is approximately twice the capillary force of gas-liquid, gas-solid, liquid-solid, and gas-liquid-solid multiphases. The seepage resistance is significantly greater than that of a single heterogeneous composite flooding system, which can better expand the sweep coefficient and improve the recovery rate.

[0018] In some embodiments, in the liquid phase, the concentration of the soft solid phase is 0-10%, and the concentration of the hard solid phase is 0-10%.

[0019] In the present invention, the solid phase is divided into a soft solid phase and a hard solid phase, and the liquid phase is used as a carrier (dispersion medium), wherein the concentration of the soft solid phase in the liquid phase is 0-10%, and the concentration of the hard solid phase is 0-10%.

[0020] In some embodiments, the soft solid phase is a viscoelastic particle displacement agent (PPG).

[0021] In the present invention, the viscoelasticity of the viscoelastic particle displacement agent (PPG) can be controlled.

[0022] In some preferred embodiments, the soft solid phase is polyacrylamide having a molecular structure in which cross-linking and branching coexist.

[0023] In the present invention, the soft solid phase has a molecular structure in which cross-linking and branching coexist, and its performance combines the advantages of both linear polyacrylamide and cross-linked polyacrylamide: it has excellent temperature and salt resistance, shear resistance, and long-term thermal stability, and it also has excellent deformation ability. It can migrate to the deep reservoir through the rock pore throat under a certain displacement pressure difference.

[0024] In some preferred embodiments, the elastic modulus of the soft solid is 6-12 Pa; and the ratio of the particle size of the soft solid phase to the average pore throat diameter of the reservoir is 17-33.

[0025] In the present invention, the average reservoir pore throat diameter is obtained through mercury injection experiments to characterize the average size of the reservoir pore throats:

[0026] In some preferred embodiments, the particle size of the soft solid is 20-200 mesh.

[0027] In the present invention, the particle size of the soft solid phase is selected based on the elastic modulus and the ratio of particle size to pore throat diameter. After extensive research, the inventors found that the elastic modulus characterizes the ease with which a material undergoes elastic deformation under a certain stress, and the larger the elastic modulus, the more difficult it is to deform. Under the same elastic modulus and pore throat diameter conditions, the larger the soft solid phase particle size, the greater the resistance to passing through the pore throat. For example, when the average pore throat diameter of the reservoir is 20-28μm, the particle size to pore diameter ratio is 17-33, and the elastic modulus is 6-12Pa, selecting a soft solid phase particle size of 20-200 mesh has better oil recovery results.

[0028] In some embodiments, the hard solid phase is selected from at least one of clay, quartz sand, ceramsite, coal powder, resin-coated clay, resin-coated ceramsite, resin-coated quartz sand, resin-coated coal powder, rock chips, asbestos, aluminum oxide, silicon dioxide, activated carbon, sulfur, carbon nanotubes, iron oxide, titanium oxide, graphene, and zinc oxide.

[0029] In some preferred embodiments, the ratio of the particle size of the hard solid phase to the average pore throat diameter of the reservoir is 1:2-3.

[0030] In this invention, the particle size of the hard solid phase is selected to match the pore size of the reservoir rock. The particle size design of the hard solid phase is based on the "1 / 3 bridging theory." Reservoir pore throat diameters are classified, and the reservoir is designed to be plugged using the hard solid phase. Through extensive research, the inventors have found that a hard solid phase particle size between 1 / 3 and 1 / 2 the average pore throat diameter of the target reservoir creates a bridging effect, increasing seepage resistance and broadening the sweep coefficient.

[0031] In some embodiments, the liquid phase comprises water or an aqueous chemical solution.

[0032] In the present invention, the chemical agent is selected from substances that can be dissolved in water and increase the viscosity of the water.

[0033] In some preferred embodiments, the concentration of the chemical in the aqueous chemical solution is 500-3000 mg / L.

[0034] In some preferred embodiments, the chemical agent contained in the aqueous chemical agent solution is at least one selected from the group consisting of partially hydrolyzed polyacrylamide, copolymers of acrylamide and olefinic monomers, biopolymers, cellulose ether chemicals, polyvinyl pyrrolidone, and surfactants.

[0035] In the present invention, the addition of polymer can improve the oil-water mobility ratio and expand the sweep coefficient. The addition of surfactant can reduce the oil-water interfacial tension and improve the oil displacement efficiency.

[0036] In some preferred embodiments, the vinyl monomer is selected from 2-acrylamide-2-methylpropanesulfonic acid, styrene or N-vinyl-2-pyrrolidone.

[0037] In some preferred embodiments, the biopolymer is selected from at least one of xanthan gum, guar gum, and fennel gum.

[0038] In some preferred embodiments, the cellulose ether chemical is selected from at least one of hydroxypropyl methylcellulose, hydroxyethyl cellulose and methyl cellulose.

[0039] In some preferred embodiments, the surfactant is selected from anionic surfactants, cationic surfactants or nonionic surfactants.

[0040] In the present invention, the anionic surfactant includes, but is not limited to, at least one of petroleum sulfonates, petroleum carboxylates, lignin sulfonates, alkylbenzene sulfonates, synthetic alkylbenzene sulfonates and polyoxyethylene ether sulfonates.

[0041] The cationic surfactant includes, but is not limited to, at least one of a quaternary ammonium salt type cationic surfactant, an amine salt type cationic surfactant, and a heterocyclic type cationic surfactant.

[0042] The nonionic surfactant includes, but is not limited to, at least one of fatty alcohol polyoxyethylene ether, alkylphenol polyoxyethylene ether, fatty acid polyoxyethylene ester, fatty amine polyoxyethylene ether, alkyl alcohol amide polyoxyethylene ether, block polyoxyethylene-polyoxypropylene ether, alkyl alcohol amide and alkyl polyglucoside.

[0043] In some preferred embodiments, the mass percentage of the surfactant in the chemical aqueous solution is 0.1-3%.

[0044] In some embodiments, the liquid phase further comprises: a foaming agent solution, and the content of the foaming agent solution is 0.05-0.5 wt % based on the total weight of the system.

[0045] In some preferred embodiments, the mass percentage of the foaming agent contained in the foaming agent solution is 0.05-0.5%.

[0046] In some preferred embodiments, the foaming agent contained in the foaming agent solution is at least one selected from the group consisting of sodium α-olefin sulfonate, heavy alkylbenzene sulfonate and petroleum sulfonate.

[0047] In the present invention, the addition of a foaming agent into the liquid phase can enrich the foam at the gas-liquid or gas-solid interface to form a gas-liquid or gas-solid stable foam system.

[0048] In some embodiments, the gas phase is selected from at least one of air, nitrogen, carbon dioxide, and natural gas.

[0049] In some embodiments, the volume ratio of the gas phase to the liquid phase is 1:2-2:1.

[0050] The present invention forms a gas-liquid two-phase interface by controlling the volume ratio of the gas phase to the liquid phase, thereby increasing the seepage resistance and expanding the swept volume.

[0051] In some preferred embodiments, the volume ratio of the gas phase to the sum of the soft solid phase and the hard solid phase is 100-1000:1, preferably 200-300:1.

[0052] The advantages of adding a gas phase to the system of the present invention are that it can adapt to harsh reservoir environments, and the gas in the reservoir is relatively elastic, which can effectively supplement the characteristics of the soft solid phase and the hard solid phase that are not easily deformed and passed through.

[0053] The second aspect of the present invention provides the application of the aforementioned heterogeneous composite oil recovery system in oil production.

[0054] The heterogeneous composite flooding system of the present invention is mainly applicable to medium- and high-permeability reservoirs, and is particularly suitable for reservoir types such as high-temperature reservoirs, high-salinity reservoirs, high-temperature and high-salinity reservoirs, reservoirs after polymer flooding, and reservoirs with strong heterogeneity. For example, in high-temperature and high-salinity reservoirs (temperature greater than 60°C, salinity greater than 10,000 mg / L), both the gas phase and the solid phase of this flooding system have good temperature and salt resistance, enabling effective oil displacement. For heterogeneous reservoirs and reservoirs after polymer flooding, there are obvious high-permeability bands, which are prone to crossflow of the injected medium. This flooding system is a heterogeneous system that can form a multiphase interface, effectively improve heterogeneity, and achieve good oil displacement results.

[0055] A third aspect of the present invention provides an oil recovery method, which comprises: injecting the aforementioned heterogeneous composite oil recovery system into a target oil reservoir to form a multiphase composed of a gas / solid interface, a gas / liquid interface, a liquid / solid interface and a gas / liquid / solid interface in the target oil reservoir.

[0056] The heterogeneous composite flooding system of the present invention includes: a gas phase, a liquid phase and a solid phase. In the following embodiments, unless otherwise specified, the solid phase includes a soft solid phase and a hard solid phase.

[0057] During the injection process of the heterogeneous composite flooding system, the gas, liquid and solid phases are preferably injected together. If the conditions for joint injection are not met, the segmented plug injection method can also be used.

[0058] In the present invention, the gas phase, liquid phase and solid phase are injected together, and the gas phase, liquid phase and solid phase are uniformly mixed according to the designed ratio using a ground mixing device. The mixed system can be injected continuously or in stages.

[0059] In some embodiments, the injection process includes: mixing a gas phase, a liquid phase, and a solid phase to form a mixed system, and then continuously injecting the mixed system into the target oil reservoir.

[0060] Furthermore, the continuous injection specifically includes the following steps:

[0061] (1) Based on the solubility curve of the gas phase in the liquid phase containing the solid phase, determine the minimum pressure required for the gas to completely dissolve;

[0062] Specifically, the solubility curve of the gas phase in the liquid phase containing the solid phase (including the soft solid phase and / or the hard solid phase) is tested to obtain the solubility of the gas phase in the liquid phase containing the solid phase under different pressure conditions, and to determine the minimum pressure required for the gas to be completely dissolved.

[0063] In the steps of the present invention, the solubility curve of the gas phase in the liquid phase containing the solid phase under different pressure conditions can be used to clearly determine the solubility of the gas phase in the liquid phase containing the solid phase, that is, the amount of gas completely dissolved at a certain pressure; or the minimum pressure required for the complete dissolution of a fixed gas.

[0064] (2) mixing the liquid phase, the soft solid phase, and the hard solid phase to obtain a liquid-solid mixture;

[0065] (3) The liquid-solid mixture is mixed with the gas phase, and pressurized according to the minimum pressure obtained in step (1) so that the gas phase is completely dissolved in the liquid-solid mixture, and then the pressure is gradually reduced to the injection pressure. During the pressure reduction process, the gas phase gradually precipitates from the liquid phase, and the gas phase grows with the soft solid phase and the hard solid phase as heterogeneous nucleation cores to form bubbles, forming a multiphase consisting of a gas / solid interface, a liquid / solid interface, and a gas / liquid / solid interface.

[0066] In this step, the liquid-solid phase and the gas phase are mixed in a designed ratio. The pressure is increased to the desired pressure, compared to the pressure required to completely dissolve the fixed amount of gas in step (1), so that the gas phase completely dissolves into the liquid phase containing the soft solid phase and the hard solid phase. Then, the pressure is gradually reduced to the designed injection pressure. During the pressure reduction process, gas precipitates from the liquid phase. At this time, the soft solid phase and the hard solid phase provide heterogeneous nucleation cores for the gas precipitation to form bubbles. The gas phase rests on the surface of the solid phase and grows around it as the core, forming gas-solid, liquid-solid, and gas-liquid-solid multiphase interfaces in the entire system.

[0067] Taking the following specific implementation method as an example, the continuous injection includes: dispersing the gas phase, soft solid phase and hard solid phase in the liquid phase with the liquid phase as the carrier, wherein the volume ratio of the gas phase to the liquid phase is 1:1, the gas phase is carbon dioxide, and the liquid phase is clean water, wherein the foaming agent sodium α-olefin sulfonate (concentration is 0.2%), polyacrylamide (concentration is 0.15%), soft solid phase (polyacrylamide viscoelastic soft solid particles with partially branched and partially cross-linked structure characteristics, concentration is 0.05%), and hard solid phase (coal powder, concentration is 0.05%) are added to form a heterogeneous composite oil recovery system, and continuous injection is performed according to the designed injection rate and injection pressure.

[0068] In other embodiments, the injection process includes:

[0069] The gas phase, liquid phase and solid phase are mixed to form a mixed system, and then the mixed system is injected into the target reservoir in sections.

[0070] In some preferred embodiments, the segmented plug injection specifically comprises the following steps: alternately injecting 0.05-0.2 PV of a heterogeneous composite flooding system and 0.05-0.2 PV of formation water.

[0071] Specifically, first inject 0.05-0.2PV (preferably 0.1PV) of heterogeneous composite oil recovery system, then inject 0.05-0.2PV (preferably 0.1PV) of formation water, then inject 0.05-0.2PV (preferably 0.1PV) of heterogeneous composite oil recovery system, then inject 0.05-0.2PV (preferably 0.1PV) of formation water, and repeat this process alternately.

[0072] During the co-injection in the present invention, the gas phase, liquid phase and solid phase are evenly distributed, forming a gas / liquid / solid three-phase interface in the oil displacement system, giving full play to the multiphase interface effect of the heterogeneous composite oil displacement system, so as to obtain a better enhanced recovery effect.

[0073] In some other embodiments, the injection process includes: first injecting a liquid phase into the target reservoir, and then injecting a gas phase to form a foam system; then injecting the liquid phase in sequence to form a liquid phase slug, injecting a soft solid phase to form a soft solid phase slug, and injecting a hard solid phase to form a hard solid phase slug, the injection volume of each slug is 0.05-0.2PV, preferably 0.1PV, and the above operation is repeated 3-5 times.

[0074] In the present invention, the gas phase is a foam system, that is, the gas phase and the liquid phase are mixed underground, that is, the liquid phase slug is injected first (for example, a foaming agent sodium α-olefin sulfonate with a concentration of 0.2% is added to clean water), and then the gas phase slug (for example, carbon dioxide) is injected. At this time, a foam system is formed underground, showing a plugging effect. This is the gas phase plugging stage; the liquid phase slug (for example, polyacrylamide with a concentration of 0.15%) is continuously injected. The liquid phase at this time has a better plugging effect than the previous gas phase slug and can expand the spread. This is the liquid phase plugging stage; the injection is continued. Soft solid phase plugs (for example, polyacrylamide with a concentration of 0.15% and polyacrylamide viscoelastic soft solid particles with a concentration of 0.05%). The soft solid phase at this time has a better sealing effect than the previous liquid phase and can continue to expand the swept volume. This is the soft solid phase plugging stage; continue to inject hard solid phase plugs (for example, polyacrylamide with a concentration of 0.15% and coal powder with a concentration of 0.05%) to achieve hard solid phase plugging of the high permeability layer and continuously expand the swept volume. The injection volume of each plug is 0.1PV, and the above operation is repeated 3-5 times.

[0075] In some embodiments, the target oil reservoir has a temperature of 60° C.-120° C. and a salinity of 3000 mg / L-30000 mg / L.

[0076] In some preferred embodiments, the target oil reservoir is a medium-high permeability oil reservoir, a high-temperature oil reservoir, a high-salinity oil reservoir, a high-temperature high-salinity oil reservoir, a post-polymer flooding oil reservoir, or a highly heterogeneous oil reservoir.

[0077] In the present invention, the slug size, chemical concentration, gas injection rate and solid injection rate of the heterogeneous composite flooding system are optimized by physical simulation experiments. If physical simulation experiments are not available, the heterogeneous composite flooding slug size and chemical concentration can be designed according to the conclusions of reservoir dynamic analysis research.

[0078] The heterogeneous composite flooding system provided by the present invention has a better oil recovery effect. This is because, compared with the solid phase and liquid phase, the gas phase has better elasticity and stronger deformation ability. When the gas phase, liquid phase and solid phase are injected simultaneously, on the one hand, part of the gas phase can adhere to the surface of the solid phase, which is equivalent to putting "soft clothes" on the solid phase, ensuring that the solid phase has good elasticity and can achieve good deformation and permeability; on the other hand, part of the gas phase and the solid phase migrate in coordination, which is equivalent to adding a "sponge cushion" to the solid phase. The above two aspects have a better effect of increasing the elasticity of the solid phase. When screening viscoelastic solid phase particles, the size range of the optional particles becomes larger, which is conducive to on-site implementation and guarantees the effect of improving oil reservoir recovery.

[0079] The present invention will be described in detail below through examples. In the following examples and comparative examples, a high-temperature, high-salt, high-calcium and magnesium oil reservoir with a temperature of 80°C and a salinity of 10,000 mg / L was used as the research object, and CMG software was used to conduct numerical simulation research on the mining effects of the examples and comparative examples.

[0080] In the following examples and comparative examples, unless otherwise specified, all reagents involved are commercially available products and can be purchased through commercial channels.

[0081] In the following examples, the copolymer of acrylamide and acrylic monomers is selected from a copolymer of acrylamide and 2-acrylamide-2-methylpropanesulfonic acid (Beijing Hengju Group Co., Ltd.);

[0082] The biopolymer is preferably selected from xanthan gum (Ordos Zhongxuan Biochemical Co., Ltd.);

[0083] The cellulose ether chemical was selected from hydroxypropyl methylcellulose (Shandong Linyi Lusen Chemical Co., Ltd.);

[0084] The foaming agent is selected from sodium α-olefin sulfonate (Henan Xinzhi Chemical Products Co., Ltd.);

[0085] The viscoelastic particle displacement agent is selected from partially branched and partially cross-linked polyacrylamide (Shengli Petroleum Administration Bureau Co., Ltd.);

[0086] The experimental results were verified through indoor physical simulation of oil displacement experiments. The simulated oil displacement experimental device includes an injection pump, an intermediate container, a core holder, and a produced fluid collection unit. During the experiment, crude oil, reservoir water, oil displacement agent, and carbon dioxide were respectively placed in the intermediate container. The core was placed in the core holder with a permeability of 3000 millidarcy, a length of 30 cm, and a diameter of 2.54 cm. The core was vacuumed and saturated with water. The core porosity was calculated based on the saturated water volume. Crude oil (viscosity 145 mPa·s at 50°C) was used to displace the water in the core, i.e., saturated oil. The saturated oil volume V was calculated based on the amount of water displaced. 饱和油 Then, displacement was carried out according to the experimental design, and crude oil volume V was separated from the produced fluid.采油量 . The recovery factor is calculated.

[0087] Recovery factor = V 采油量 / V 饱和油 *100%.

[0088] Example 1

[0089] Waterflooding was performed at a rate of 2 PV, achieving a recovery of 43.3%. The oil was then injected sequentially at a rate of 0.1 PV of carbon dioxide, followed by 0.1 PV of a 0.15% polyacrylamide solution, and then 0.1 PV of a 0.15% polyacrylamide solution plus 0.05% viscoelastic solid particles. This process was repeated for a total of 2 PV, and the oil was then switched to waterflooding. The final recovery was 67.3%, an enhanced recovery of 24%.

[0090] Example 2

[0091] Waterflooding was carried out at a rate of 2 PV, achieving a recovery of 42.3%. Subsequently, 0.1 PV of 0.2% foaming agent solution, 0.1 PV of carbon dioxide, 0.1 PV of 0.15% polyacrylamide solution, and 0.1 PV of 0.15% polyacrylamide plus 0.05% viscoelastic solid particles were injected. This process was repeated for a total of 2 PV, and the oil was then switched to waterflooding. The final recovery was 68.9%, an enhanced recovery of 26.6%.

[0092] Example 3

[0093] Waterflooding was performed at a rate of 2 PV, achieving a recovery of 42.8%. Subsequently, 0.1 PV of a 0.2% foaming agent solution, 0.1 PV of carbon dioxide, 0.1 PV of a 0.15% polyacrylamide solution, 0.1 PV of 0.15% polyacrylamide plus 0.05% viscoelastic solid particles, and 0.1 PV of 0.15% polyacrylamide plus 0.05% hard solid particles were injected sequentially. This process was repeated for a total of 2 PV, and the oil was then switched to waterflooding. The final recovery was 77.9%, an enhanced recovery of 35.1%.

[0094] Example 4

[0095] Waterflooding at 2 PV resulted in a 42.0% recovery. A 0.15% polyacrylamide solution, 0.05% viscoelastic solid particles, 0.05% hard solid particles, and 0.2% frother solution (1 PV) were thoroughly mixed with 1 PV of carbon dioxide and injected continuously for a total of 2 PV. Waterflooding was then continued. The final recovery was 81.3%, an enhanced recovery of 39.3%.

[0096] Example 5

[0097] Waterflooding at 2 PV resulted in a 42.0% recovery. A 0.1 PV of 0.15% polyacrylamide solution, 0.05% viscoelastic solid particles, 0.05% hard solid particles, and 0.2% frother solution were thoroughly mixed with 0.1 PV of carbon dioxide. This was then alternating with 0.2 PV of waterflooding, resulting in a total of 2 PV of injection. Waterflooding was then continued. The final recovery was 81%, an enhanced recovery of 39%.

[0098] Comparative Example 1

[0099] Waterflooding was performed at 2 PV, achieving a recovery of 41.6%. Subsequently, 0.1 PV of 0.15% polyacrylamide solution, 0.1 PV of 0.2% foaming agent solution, and 0.1 PV of carbon dioxide were injected sequentially. This process was repeated for a total of 2 PV, and the oil was switched to waterflooding. The final recovery was 58.9%, an enhanced recovery of 17.3%.

[0100] Comparative Example 2

[0101] Water flooding was carried out for 2 PV, with a recovery of 42.5%. A 0.15% polyacrylamide solution was then injected for a total of 2 PV, and the oil was switched to water flooding. The final recovery was 54.9%, an enhanced recovery of 12.4%.

[0102] Comparative Example 3

[0103] Waterflooding was performed at 2 PV, achieving a recovery of 44.2.6%. Then, 0.1 PV of a 0.2% foaming agent solution and 0.1 PV of carbon dioxide were injected. This process was repeated for a total of 2 PV, and the system switched to waterflooding. The final recovery was 56.7%, an enhanced recovery of 12.1%.

[0104] Comparative Example 4

[0105] Waterflooding was carried out at a rate of 2PV, achieving a recovery of 43.1%. Then, 0.15% polyacrylamide and 0.05% viscoelastic solid particles were injected, totaling 2PV, before switching to waterflooding. The final recovery was 54.0%, an enhanced recovery of 10.9%.

[0106] Comparative Example 5

[0107] Waterflooding was carried out at 2PV, with a recovery of 43.4%. Then, 0.15% polyacrylamide and 0.05% hard solid particles were injected, totaling 2PV, and the oil was switched to waterflooding. The final recovery was 53.5%, an enhanced recovery of 10.1%.

[0108] The relevant parameters in the above embodiments and comparative examples are listed in Table 1.

[0109] Table 1

[0110]

[0111] The results in Table 1 show that both the heterogeneous composite flooding system and the flooding method affect crude oil recovery. Example 4 employed a foaming agent solution, carbon dioxide, a polyacrylamide solution, viscoelastic solid particles, and hard solid particles as a heterogeneous composite flooding system. By thoroughly mixing these substances and then continuously injecting them, the final recovery rate was 81.3%, and the enhanced recovery rate was 39.3%. By comparison, Example 5 of the present invention achieved significantly better results.

[0112] The preferred embodiments of the present invention have been described in detail above, but the present invention is not limited thereto. Within the technical concept of the present invention, various simple variations of the technical solution of the present invention may be made, including combining the various technical features in any other appropriate manner. These simple variations and combinations should also be regarded as disclosed in the present invention and fall within the scope of protection of the present invention.

Claims

1. An oil displacement method, characterized in that: The oil displacement method comprises: injecting a heterogeneous composite oil displacement system into a target oil reservoir to form a multiphase composed of a gas / solid interface, a gas / liquid interface, a liquid / solid interface, and a gas / liquid / solid interface in the target oil reservoir; The injection process includes: mixing the gas phase, liquid phase and solid phase to form a mixed system, and then continuously injecting the mixed system into the target oil reservoir; The continuous injection specifically comprises the following steps: (1) Based on the solubility curve of the gas phase in the liquid phase containing the solid phase, determine the minimum pressure required for the gas to completely dissolve; (2) mixing the liquid phase, the soft solid phase, and the hard solid phase to obtain a liquid-solid mixture; (3) mixing the liquid-solid mixture with the gas phase, pressurizing the mixture according to the minimum pressure obtained in step (1) so that the gas phase is completely dissolved in the liquid-solid mixture, and then gradually reducing the pressure to the injection pressure. During the pressure reduction process, the gas phase gradually precipitates from the liquid phase, and the gas phase grows with the soft solid phase and the hard solid phase as heterogeneous nucleation cores to form bubbles, forming a multiphase consisting of a gas / solid interface, a liquid / solid interface, and a gas / liquid / solid interface; The heterogeneous composite oil displacement system includes: a gas phase in a gaseous state under underground oil reservoir conditions, a liquid phase in a liquid state under underground oil reservoir conditions, and a solid phase in a solid state under underground oil reservoir conditions; wherein the volume ratio of the gas phase to the liquid phase is 1:4-4:1; the solid phase includes a soft solid phase and a hard solid phase, and the weight ratio of the soft solid phase to the hard solid phase is 10:1-1:10; the soft solid phase is a viscoelastic particle oil displacement agent; the elastic modulus of the soft solid is 6-12 Pa, and the ratio of the particle size of the soft solid phase to the average pore throat diameter of the reservoir is 17-33; the ratio of the particle size of the hard solid phase to the average pore throat diameter of the reservoir is 1:2-3; and the particle size of the soft solid is 20-200 mesh.

2. The oil displacement method according to claim 1, wherein In the liquid phase, the concentration of the soft solid phase is 0-10%, and the concentration of the hard solid phase is 0-10%.

3. The oil displacement method according to claim 1 or 2, wherein: The soft solid phase is polyacrylamide with a molecular structure in which cross-linking and branching coexist.

4. The oil displacement method according to claim 1 or 2, wherein: The hard solid phase is selected from at least one of clay, quartz sand, ceramsite, coal powder, resin-coated clay, resin-coated ceramsite, resin-coated quartz sand, resin-coated coal powder, rock chips, asbestos, aluminum oxide, silicon dioxide, activated carbon, sulfur, carbon nanotubes, iron oxide, titanium oxide, graphene, and zinc oxide.

5. The oil displacement method according to claim 1 or 2, wherein: The liquid phase includes water or a chemical aqueous solution.

6. The oil displacement method according to claim 5, wherein: The concentration of the chemical in the chemical aqueous solution is 0.05-5%; And / or, the chemical agent contained in the chemical agent aqueous solution is at least one selected from partially hydrolyzed polyacrylamide, a copolymer of acrylamide and olefin monomers, biopolymer, cellulose ether chemicals, polyvinyl pyrrolidone and surfactant.

7. The oil displacement method according to claim 6, wherein: The vinyl monomer is selected from 2-acrylamide-2-methylpropanesulfonic acid, styrene or N-vinyl-2-pyrrolidone; and / or, The biopolymer is selected from at least one of xanthan gum, guar gum and fennel gum; and / or, The cellulose ether chemical is at least one selected from hydroxypropyl methylcellulose, hydroxyethyl cellulose and methyl cellulose; and / or, The surfactant is selected from anionic surfactants, cationic surfactants or nonionic surfactants.

8. The oil displacement method according to claim 7, wherein: The mass percentage of the surfactant in the chemical aqueous solution is 0.01-5%.

9. The oil displacement method according to claim 1 or 2, wherein: The liquid phase further comprises a foaming agent solution, wherein the content of the foaming agent solution is 0.05-0.5% based on the total weight of the system.

10. The oil displacement method according to claim 9, wherein: The foaming agent contained in the foaming agent solution is at least one selected from sodium α-olefin sulfonate, heavy alkylbenzene sulfonate and petroleum sulfonate.

11. The oil displacement method according to claim 1 or 2, wherein: The gas phase is selected from at least one of air, nitrogen, carbon dioxide and natural gas.

12. The oil displacement method according to claim 11, wherein: The volume ratio of the gas phase to the liquid phase is 1:2-2:1; And / or, the volume ratio of the gas phase to the sum of the soft solid phase and the hard solid phase is 100-1000:

1.

13. The oil displacement method according to claim 12, wherein: The volume ratio of the gas phase to the sum of the soft solid phase and the hard solid phase is 200-300.

14. The oil displacement method according to claim 1, wherein: The target oil reservoir has a temperature of 60° C.-120° C. and a salinity of 3000 mg / L-30000 mg / L.

15. The oil displacement method according to claim 14, wherein: The target oil reservoir is a medium-high permeability oil reservoir, a high-temperature oil reservoir, a high-salinity oil reservoir, a high-temperature high-salinity oil reservoir, a post-polymer flooding oil reservoir, or a highly heterogeneous oil reservoir.

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