A formation in-situ self-emulsification composite plugging and adjustment method

Abstract

The present invention provides a formation in-situ self-emulsification composite plugging method, which relates to the technical field of oil and gas field development, and comprises the following steps: S1: injecting a pre-segment plug of an in-situ emulsification viscosity-increasing system into the formation; S2: injecting a main segment plug of an in-situ emulsification viscosity-increasing system into the formation; S3: injecting a protective segment plug of an in-situ emulsification viscosity-increasing system into the formation; S4: injecting a post-segment plug of an in-situ emulsification viscosity-increasing system into the formation; S5: injecting a displacement segment plug into the formation. The pre-segment plug, the main segment plug, the protective segment plug, the post-segment plug and the displacement segment plug in the method all adopt an in-situ emulsification viscosity-increasing system of different concentrations, and are suitable for oil displacement in highly mineralized, high-temperature and high-water-content oil wells.

Description

Technical Field

[0001] The invention relates to the technical field of oil and gas field development, and in particular to a formation in-situ self-emulsification composite plugging and adjustment method. Background Art

[0002] The developed or proven oil and gas fields in my country are mainly continental sedimentary oil fields, with large differences in reservoir permeability and strong heterogeneity. With the deepening of oil field development, the water content of water drive increases faster and the water drive efficiency is low. In the late stage of water drive oil production, 60% to 70% of the original oil is still stored in the oil layer. Therefore, how to improve the recovery rate of the remaining oil is the key to increasing and stabilizing the production of high-water-content oil fields. Reservoir heterogeneity is one of the main factors affecting the efficient development of high-temperature and high-salinity oil reservoirs. To improve the effect of water drive development in the middle and late stages of high-temperature and high-salinity oil reservoirs, it is first necessary to control the heterogeneity of the formation. However, the complex conditions of high-temperature and high-salinity oil reservoirs, such as deep burial, high temperature, and high mineralization of formation water, have become technical difficulties in improving reservoir heterogeneity. In response to the problem that improved water flooding technology represented by polymers is not suitable for application in high-temperature (>90℃) and high-salinity reservoirs, some scholars have proposed an emulsified viscosity-enhancing oil recovery system. This system quickly forms an oil-external phase emulsion with crude oil under certain shear conditions. The oil-external phase emulsion has a large particle size and is kinetically stable but thermodynamically unstable. It is easy to demulsify, and thus has a higher viscosity than crude oil when the water-oil ratio is high.

[0003] Patent CN110079291A reports an in-situ emulsifying and thickening system containing a high phase change point, which is composed of the following components by weight percentage: 0.2-0.5% water-soluble surfactant, 0.2-1.5% oil-soluble surfactant, 0.02-0.5% lipophilic colloidal particles, 0.02-0.2% carrier, and the rest is mineralized water. The water-soluble surfactant is one or a combination of petroleum sulfonate, cocamidopropyl betaine, fatty alcohol ether sulfonate, alkanolamide, and alkyl glycoside; the oil-soluble surfactant is one or a combination of propylene glycol monostearate, fatty acid glyceride, polyoxyethylene sorbitan monostearate, polyoxyethylene fatty alcohol ether, oleic acid diethanolamide, dodecylamine, octadecyl primary amine, sodium oleate, and petroleum acid; the lipophilic colloidal particles are one of liquid paraffin, graphite powder, and cage-type polysilsesquioxane; the carrier is one of carboxymethyl-β-cyclodextrin, chitosan quaternary ammonium salt, chitosan hydrochloride, xanthan gum, and guar gum. The system is used for water-flooded oil reservoirs and can significantly improve the development effect of water-flooded heavy oil reservoirs. Patent CN106812509A reports an oil recovery method assisted by carbon dioxide throughput by a polymer-surface binary flooding system, which belongs to the technical field of improving crude oil recovery. The method comprises: sequentially injecting a pre-segment plug of a polymer-surface binary flooding system, a main carbon dioxide segment plug, a post-segment plug of a polymer-surface binary flooding system, a plugging agent segment plug and water into an oil reservoir; after the well is shut down for a preset time, the well is opened to produce crude oil; the pre-segment plug of the polymer-surface binary flooding system and the post-segment plug of the polymer-surface binary flooding system comprise the following components in mass percentage: polyacrylamide, 0.10% to 0.40%; a surfactant compounded with dodecyldimethylamine ethyl lactone and hexadecyltrimethylammonium bromide, 0.05% to 0.20%; water, the balance; the plugging agent segment comprises the following components in mass percentage: partially hydrolyzed polyacrylamide, 0.25% to 0.50%; a cross-linking agent, 0.20% to 0.50%; a stabilizer: 0.01% to 0.03%; a pH regulator: 0.01% to 0.02%; and water, the balance. The method can reasonably control the mobility ratio, improve the oil washing efficiency and carbon dioxide utilization rate, and improve the recovery rate.

[0004] In the middle and late stages of water flooding development, due to the adverse effect of oil-water mobility, water flows along the high permeability layer and bypasses the high oil content area, leaving a large amount of crude oil unaffected, resulting in a low water drive recovery rate. According to statistics, the recovery rate of crude oil in my country's onshore oil fields after elastic energy recovery and water drive recovery is less than 40%. Among these high-water-content oil fields, high-temperature (above 90°C) and high-salt (formation water mineralization above 30,000 mg / L) Class III oil reservoirs account for a considerable proportion, with a total proven geological reserve of more than 8 billion tons. In view of the geological characteristics of ultra-high temperature and ultra-high salt and the properties of crude oil, it is urgent to find a new efficient oil recovery technology. Summary of the invention

[0005] The present invention aims at solving the problems in the prior art and provides a formation in-situ self-emulsification composite plugging and adjustment method. The front slug, main slug, protection slug, rear slug and displacement slug in the method all adopt in-situ emulsification viscosity increasing system of different concentrations, which is suitable for oil displacement of high-mineralization, high-temperature and high-water-content oil wells.

[0006] To achieve the above purpose, the technical solution adopted by the present invention is as follows:

[0007] The present invention provides a formation in-situ self-emulsification composite plugging and adjustment method, comprising the following steps:

[0008] S1: Inject the pre-slug of the in-situ emulsified viscosity-enhancing system into the formation;

[0009] S2: injecting the main slug of the in-situ emulsified viscosity increasing system into the formation;

[0010] S3: Injecting an in-situ emulsified viscosity-enhancing system into the formation to protect the slug;

[0011] S4: injecting an in-situ emulsified viscosity increasing system into the formation and placing a slug;

[0012] S5: injecting a displacement slug into the formation;

[0013] The front slug, main slug, protection slug and rear slug all adopt an in-situ emulsification and viscosity increasing system.

[0014] Furthermore, the in-situ emulsified viscosity increasing system used in the front segment plug in step S1 comprises, by weight percentage: 0.6-0.8% of a water-soluble surfactant, 0.15-0.25% of an oil-soluble surfactant, 0.01-0.05% of lipophilic colloidal particles, 0.01-0.05% of a carrying agent, and the rest is mineralized water.

[0015] Preferably, the in-situ emulsified viscosity increasing system used in the front slug in step S1 comprises, by weight percentage: 0.8% of a water-soluble surfactant, 0.2% of an oil-soluble surfactant, 0.02% of lipophilic colloidal particles, 0.02% of a carrying agent, and the remainder is mineralized water.

[0016] Furthermore, the in-situ emulsified viscosity increasing system used in the main segment plug in step S2 comprises, by weight percentage: 0.15-0.3% of a water-soluble surfactant, 1.3-1.8% of an oil-soluble surfactant, 0.3-0.6% of lipophilic colloidal particles, 0.08-0.15% of a carrying agent, and the remainder being mineralized water.

[0017] Preferably, the in-situ emulsified viscosity increasing system used in the main body plug in step S2 comprises, by weight percentage: 0.2% of a water-soluble surfactant, 1.5% of an oil-soluble surfactant, 0.5% of lipophilic colloidal particles, 0.1% of a carrying agent, and the remainder being mineralized water.

[0018] Furthermore, the in-situ emulsified viscosity increasing system used in the protection segment plug in step S3 comprises, by weight percentage: 0.15-0.3% of a water-soluble surfactant, 1.4-1.6% of an oil-soluble surfactant, 1.3-1.8% of lipophilic colloidal particles, 0.2-0.3% of a carrying agent, and the remainder is mineralized water.

[0019] Preferably, the in-situ emulsified viscosity increasing system used for protecting the segment plug in step S3 comprises, by weight percentage: 0.2% of a water-soluble surfactant, 1.5% of an oil-soluble surfactant, 1.5% of lipophilic colloidal particles, 0.2% of a carrying agent, and the remainder being mineralized water.

[0020] Furthermore, the in-situ emulsified viscosity increasing system used in the post-slug in step S4 comprises, by weight percentage: 0.9-1.2% of a water-soluble surfactant, 0.35-0.45% of an oil-soluble surfactant, 0.3-0.6% of lipophilic colloidal particles, 0.01-0.05% of a carrying agent, and the remainder is mineralized water.

[0021] Preferably, the in-situ emulsification and viscosity increasing system used in the post-slug in step S4 comprises, by weight percentage: 1% of a water-soluble surfactant, 0.4% of an oil-soluble surfactant, 0.5% of lipophilic colloidal particles, 0.02% of a carrying agent, and the remainder being mineralized water.

[0022] Furthermore, the displacement slug in step S5 is formation water.

[0023] Furthermore, the in-situ emulsification and thickening system used in the main body slug also includes supercritical carbon dioxide, wherein the content of supercritical carbon dioxide in the in-situ emulsification and thickening system used in the main body slug is 0.005%.

[0024] Furthermore, the water-soluble surfactant is one or more of petroleum sulfonate, cocamidopropyl betaine, fatty alcohol ether sulfonate, alkanolamide and alkyl glycoside; the oil-soluble surfactant is one or more of propylene glycol monostearate, fatty acid glyceride, polyoxyethylene sorbitan monostearate, polyoxyethylene fatty alcohol ether, oleic acid diethanolamide, dodecylamine, octadecyl primary amine, sodium oleate and petroleum acid; the lipophilic colloidal particles are one or more of liquid paraffin, graphite powder and cage-type polysilsesquioxane; the carrier is one or more of carboxymethyl-β-cyclodextrin, chitosan quaternary ammonium salt, chitosan hydrochloride, xanthan gum and guar gum.

[0025] The technical effects achieved by the present invention are:

[0026] (1) The in-situ self-emulsifying composite plugging and adjustment method disclosed in the present invention adopts an in-situ emulsifying and thickening system injection to interact with crude oil to generate a water-external phase emulsion in situ, and dynamically evolves into a near "piston" displacement in which the composite emulsification system displaces the emulsion and the emulsion displaces the crude oil. The method is suitable for oil displacement in highly mineralized, high-temperature, and high-water-content oil wells.

[0027] (2) The in-situ self-emulsifying composite plugging and adjustment method disclosed in the present invention also adds supercritical carbon dioxide to the in-situ emulsification and thickening system. Through the fluidity of supercritical carbon dioxide in the emulsion, the permeability of the gas, and the gas explosion effect produced by the change of the surface tension of the bubbles, the emulsification system is continuously emulsified, the range of influence is wider, and the oil displacement effect is better. The substances in the in-situ emulsification and thickening system promote and cooperate with each other, and ultimately the crude oil recovery rate can be increased by 33%, and the cumulative recovery rate can reach more than 80%. Once the content of the components of the system changes, it will greatly affect the final recovery rate and cumulative recovery rate. DETAILED DESCRIPTION

[0028] In view of the ultra-high temperature (140°C) and ultra-high salt (220,000, divalent ions greater than 10,000) geological characteristics and crude oil properties of the Tahe oil reservoir, a deep in-situ self-emulsifying displacement agent is developed, which utilizes the interaction between the self-emulsifier and the formation fluid (formation water and crude oil) to emulsify the displacement medium in situ, and synergistically achieves a new technology for efficient oil displacement of fluidity control and ultra-low interfacial tension oil washing. It is worth noting that the raw materials used in the present invention are all common commercial products, so there is no specific limitation on their sources.

[0029] Example 1

[0030] A formation in-situ self-emulsification composite plugging and adjustment method, comprising the following steps:

[0031] S1: Inject the pre-slug of the in-situ emulsified viscosity-enhancing system into the formation;

[0032] S2: injecting the main slug of the in-situ emulsified viscosity increasing system into the formation;

[0033] S3: Injecting an in-situ emulsified viscosity-enhancing system into the formation to protect the slug;

[0034] S4: injecting an in-situ emulsified viscosity increasing system into the formation and placing a slug;

[0035] S5: injecting a displacement slug into the formation;

[0036] The in-situ emulsified viscosity increasing system used in the front segment plug includes 0.8% of water-soluble surfactant, 0.2% of oil-soluble surfactant, 0.02% of lipophilic colloidal particles, 0.02% of carrying agent, and the rest is mineralized water.

[0037] The in-situ emulsified viscosity increasing system used in the main segment plug includes 0.2% of water-soluble surfactant, 1.5% of oil-soluble surfactant, 0.5% of lipophilic colloidal particles, 0.1% of carrying agent, and the rest is mineralized water.

[0038] The in-situ emulsified viscosity increasing system used for protecting the segment plug includes 0.2% of water-soluble surfactant, 1.5% of oil-soluble surfactant, 1.5% of lipophilic colloidal particles, 0.2% of carrying agent, and the rest is mineralized water.

[0039] The in-situ emulsified viscosity increasing system used in the post-slug includes 1% of water-soluble surfactant, 0.4% of oil-soluble surfactant, 0.5% of lipophilic colloidal particles, 0.02% of carrying agent, and the rest is mineralized water.

[0040] Taking Dagang X single well as an example, its injection slug design is:

[0041] step Implementation content Daily injection volume (cubic meters) Injection time (days) Injection volume (PV) 1 Pre-slug 120 10 days 0.1 2 Main slug 100 15 days 0.15 3 Protection Slug 120 15 days 0.15 4 Rear Slug 120 15 days 0.15 5 Replacement Slug 100 12 days 0.05

[0042] After the slug injection is completed, water is injected, and then the well is kept warm for 20-50 days before the well is opened to produce crude oil.

[0043] Water flooding to a water cut of 98%, oil recovery increased by 25%, and the cumulative recovery reached more than 80%.

[0044] Example 2

[0045] Supercritical carbon dioxide was added to the in-situ emulsification and thickening system used in the main slug, the content of supercritical carbon dioxide in the in-situ emulsification and thickening system used in the main slug was 0.005%, and the injection rate was 0.3 mL / min. The rest was basically the same as in Example 1.

[0046] After the slug injection is completed, water is injected, and then the well is kept warm for 20-50 days before the well is opened to produce crude oil.

[0047] The water drive reached a water cut of 98%, the crude oil recovery rate increased by 33%, and the cumulative recovery rate reached more than 80%.

[0048] Example 3

[0049] The only difference from Example 1 is that the in-situ emulsified viscosity increasing system used in the pre-slug includes 0.6% of water-soluble surfactant, 0.15% of oil-soluble surfactant, 0.01% of lipophilic colloidal particles, 0.01% of carrying agent, and the rest is mineralized water.

[0050] The in-situ emulsified viscosity increasing system used in the main segment plug includes 0.15% of water-soluble surfactant, 1.3% of oil-soluble surfactant, 0.3% of lipophilic colloidal particles, 0.08% of carrying agent, and the rest is mineralized water.

[0051] The in-situ emulsified viscosity increasing system used for protecting the segment plug includes 0.15% of water-soluble surfactant, 1.4% of oil-soluble surfactant, 1.3% of lipophilic colloidal particles, 0.2% of carrying agent, and the rest is mineralized water.

[0052] The in-situ emulsified viscosity increasing system used in the post-slug includes 0.9% of water-soluble surfactant, 0.35% of oil-soluble surfactant, 0.3% of lipophilic colloidal particles, 0.01% of carrying agent, and the rest is mineralized water.

[0053] The water drive reached a water cut of 98%, the crude oil recovery rate increased by 22%, and the cumulative recovery rate reached more than 76%.

[0054] Example 4

[0055] The only difference from Example 1 is that the in-situ emulsified viscosity increasing system used in the pre-slug includes 0.8% of water-soluble surfactant, 0.25% of oil-soluble surfactant, 0.05% of lipophilic colloidal particles, 0.05% of carrying agent, and the rest is mineralized water.

[0056] The in-situ emulsified viscosity increasing system used in the main segment plug includes 0.3% of water-soluble surfactant, 1.8% of oil-soluble surfactant, 0.6% of lipophilic colloidal particles, 0.15% of carrying agent, and the rest is mineralized water.

[0057] The in-situ emulsified viscosity increasing system used for protecting the segment plug includes 0.3% of water-soluble surfactant, 1.6% of oil-soluble surfactant, 1.8% of lipophilic colloidal particles, 0.3% of carrying agent, and the rest is mineralized water.

[0058] The in-situ emulsified viscosity increasing system used in the post-slug includes 1.2% of water-soluble surfactant, 0.45% of oil-soluble surfactant, 0.6% of lipophilic colloidal particles, 0.05% of carrying agent, and the rest is mineralized water.

[0059] The water drive reached a water cut of 98%, the crude oil recovery rate increased by 24%, and the cumulative recovery rate reached more than 79%.

[0060] Comparative Example 1

[0061] The only difference from Example 1 is that the in-situ emulsified viscosity increasing system used in the front segment plug includes 0.5% of water-soluble surfactant, 0.3% of oil-soluble surfactant, 0.008% of lipophilic colloidal particles, 0.06% of carrying agent, and the rest is mineralized water.

[0062] The in-situ emulsified viscosity increasing system used in the main segment plug includes 0.1% of water-soluble surfactant, 2% of oil-soluble surfactant, 0.2% of lipophilic colloidal particles, 0.2% of carrying agent, and the rest is mineralized water.

[0063] The in-situ emulsified viscosity increasing system used for protecting the segment plug includes 0.1% of water-soluble surfactant, 1.8% of oil-soluble surfactant, 1% of lipophilic colloidal particles, 0.5% of carrying agent, and the rest is mineralized water.

[0064] The in-situ emulsified viscosity increasing system used in the post-slug includes 0.7% of water-soluble surfactant, 0.5% of oil-soluble surfactant, 0.2% of lipophilic colloidal particles, 0.6% of carrying agent, and the rest is mineralized water.

[0065] Water flooding to a water cut of 98% increased crude oil recovery by 15%, with the maximum cumulative recovery being 74%.

[0066] Comparative Example 2

[0067] The only difference from Example 1 is that conventional AEC (0.6 wt %) polyoxyethylene ether sulfonate is used as the displacement system, and its injection amount is the same as that of Example 1.

[0068] The crude oil recovery rate increased by 13.7%, and the maximum cumulative recovery rate was 72.3%.

[0069] Finally, it should be noted that the above content is only used to illustrate the technical solution of the present invention, rather than to limit the scope of protection of the present invention. Simple modifications or equivalent substitutions of the technical solution of the present invention by ordinary technicians in this field do not deviate from the essence and scope of the technical solution of the present invention.

Claims

1. A formation in-situ self-emulsifying composite plugging and adjustment method, characterized by: The specific steps are as follows: S1: Inject the pre-slug of the in-situ emulsified viscosity-enhancing system into the formation; S2: injecting the main slug of the in-situ emulsified viscosity increasing system into the formation; S3: Injecting an in-situ emulsified viscosity-enhancing system into the formation to protect the slug; S4: injecting an in-situ emulsified viscosity increasing system into the formation and placing a slug; S5: injecting a displacement slug into the formation; The front slug, main slug, protection slug and rear slug all adopt an in-situ emulsification and viscosity increasing system; The in-situ emulsification and viscosity increasing system used in the front slug in step S1 comprises, by weight percentage: 0.6-0.8% of a water-soluble surfactant, 0.15-0.25% of an oil-soluble surfactant, 0.01-0.05% of lipophilic colloidal particles, 0.01-0.05% of a carrying agent, and the rest is mineralized water; The in-situ emulsified viscosity increasing system used in the main segment plug in step S2 comprises, by weight percentage: 0.15-0.3% of a water-soluble surfactant, 1.3-1.8% of an oil-soluble surfactant, 0.3-0.6% of lipophilic colloidal particles, 0.08-0.15% of a carrying agent, and the rest is mineralized water; The in-situ emulsified viscosity increasing system used in the protection segment plug in step S3 comprises, by weight percentage: 0.15-0.3% of a water-soluble surfactant, 1.4-1.6% of an oil-soluble surfactant, 1.3-1.8% of lipophilic colloidal particles, 0.2-0.3% of a carrying agent, and the rest is mineralized water; The in-situ emulsification and viscosity increasing system used in the post-slug in step S4 comprises, by weight percentage: 0.9-1.2% of a water-soluble surfactant, 0.35-0.45% of an oil-soluble surfactant, 0.3-0.6% of lipophilic colloidal particles, 0.01-0.05% of a carrying agent, and the remainder is mineralized water; The in-situ emulsification and thickening system used in the main body slug also includes supercritical carbon dioxide; the content of supercritical carbon dioxide in the in-situ emulsification and thickening system used in the main body slug is 0.005%; The lipophilic colloidal particles are one or more of liquid paraffin, graphite powder and cage-type polysilsesquioxane; The carrying agent is one or more of carboxymethyl-β-cyclodextrin, chitosan quaternary ammonium salt, chitosan hydrochloride, xanthan gum and guar gum; The water-soluble surfactant is one or more of petroleum sulfonate, cocamidopropyl betaine, fatty alcohol ether sulfonate, alkanolamide and alkyl glycoside; The oil-soluble surfactant is one or more of propylene glycol monostearate, fatty acid glyceride, polyoxyethylene sorbitan monostearate, polyoxyethylene fatty alcohol ether, oleic acid diethanolamide, dodecylamine, octadecyl primary amine, sodium oleate and petroleum acid.