A method for producing heavy oil by microemulsion imbibition flooding and fracturing assisted by steam stimulation

Abstract

The present invention belongs to the field of oil production and discloses a method for extracting heavy oil by microemulsion imbibition oil fracturing assisted by steam stimulation. The method optimizes the formula of a microemulsion imbibition oil-displacing agent based on the geological characteristics of heavy oil reservoirs developed by steam stimulation, and combines the functions of drainage assistance, viscosity reduction, and imbibition oil-displacing. The method optimizes the formula of a variable viscosity slickwater system microemulsion imbibition oil-displacing fracturing fluid based on reservoir characteristics and development difficulties, so that the concentration of the microemulsion imbibition oil-displacing agent is 0.1-0.3w%. A microemulsion imbibition oil-displacing agent pre-slug is injected into the oil well, and the dosage of the microemulsion imbibition oil-displacing agent is 0.1-0.3w% of the injected steam. Hydraulic fracturing or fracturing sand control is performed, with the fracture half-length less than 1 / 2 the well spacing. Steam is injected, and the well is then shut down for 7-10 days. The well is opened for production, and the surface activity of the flowback fluid is continuously monitored. The present invention realizes the integration of reservoir unblocking, reservoir transformation, fracturing sand control, viscosity reduction, permeability enhancement, and oil displacement, simplifies the construction process, and improves the oil production rate and recovery rate.

Description

Technical Field

[0001] The present invention belongs to the field of petroleum extraction and relates to a method for extracting heavy oil by microemulsion imbibition flooding fracturing assisted by steam huff and puff, and in particular to a microemulsion imbibition flooding fracturing fluid system for low-permeability heavy oil reservoirs and an assisted steam huff and puff oil extraction method. Background Art

[0002] With the deepening of mining in unconventional areas, the exploration and development of these areas have become increasingly important. Consequently, the need to transform these reservoirs to enable them to generate effective production capacity arises. Fracturing is the most effective and commonly used method for reservoir transformation and production enhancement.

[0003] The main purpose of existing fracturing construction is to create a crack in the reservoir, then fill it with proppant to form an artificial high-permeability flow channel in the formation. With the return of the fracturing fluid, the entire fracturing process is completed. The effectiveness of the fracturing is evaluated by the output after the fracturing well is put into production. For low-permeability heavy oil reservoirs, the reservoir properties are poor, the crude oil fluidity is poor, and steam stimulation development is extremely difficult. Fracturing-assisted steam stimulation technology effectively solves the problems of difficult steam injection and low thermal efficiency in low-permeability heavy oil reservoirs. At present, the fracturing of low-permeability heavy oil reservoirs generally adopts conventional guar gum fracturing fluid system, which has a complex chemical composition and serious damage from guar gum residue. During the fracturing and flowback process, fracturing fluid damage and cold damage are prone to occur. If steam stimulation is implemented after the fracturing flowback, the damage of the fracturing fluid will extend further into the deep reservoir.

[0004] During steam stimulation, the addition of viscosity reducers can further reduce crude oil viscosity, improve mobility, and thus enhance oil recovery. Water-soluble viscosity reducers disperse crude oil into the aqueous phase to form a stable emulsion, reducing viscosity and achieving viscosity reduction. They offer wide practical applications and low cost, but are not suitable for oilfields with low water content and have poor temperature resistance, which can hinder subsequent demulsification and dehydration. The polar groups (ester, hydroxyl, and amide) in oil-soluble viscosity reducers form stronger hydrogen bonds with asphaltene, disrupting the three-dimensional network structure formed by the colloidal asphaltene and thus reducing the viscosity of the heavy oil. While they offer excellent temperature resistance and eliminate post-processing issues, they are used at high concentrations, resulting in low viscosity reduction efficiency and poor safety.

[0005] For medium- and low-permeability heavy oil reservoirs in the late stages of steam stimulation development, where formation water storage is high, formation pressure is low, and the oil-gas ratio is low, fracturing-assisted stimulation and post-fracturing sand control steam stimulation require not only auxiliary viscosity reduction but also formation energy replenishment, oil washing, viscosity reduction, displacement, and reservoir damage prevention. Conventional drainage aids are ineffective in oil washing, viscosity reduction, and displacement, and conventional viscosity reducers have low oil washing and displacement efficiency. Summary of the Invention

[0006] To overcome the shortcomings of existing technologies, this invention combines fracturing with steam stimulation for heavy oil recovery in low-permeability reservoirs. The purpose of this invention is to develop an improved fracturing-assisted steam stimulation method for heavy oil recovery, addressing issues such as reservoir damage, poor sand control, and low oil washing, viscosity reduction, and displacement efficiency, thereby significantly improving the oil recovery rate and recovery factor in medium- and low-permeability heavy oil reservoirs in the middle and late stages of development.

[0007] The above-mentioned object of the present invention is achieved through the following technical solutions:

[0008] A method for recovering heavy oil by microemulsion imbibition flooding and fracturing assisted by steam stimulation comprises the following steps:

[0009] (1) Based on the geological characteristics of heavy oil reservoirs developed by steam stimulation, the formulation of microemulsion imbibition flooding agent is optimized to combine drainage assistance, viscosity reduction and imbibition flooding functions;

[0010] (2) Based on the reservoir characteristics and development difficulties, the formulation of the variable viscosity slick water system microemulsion imbibition displacement fracturing fluid was optimized to achieve a microemulsion imbibition displacement agent concentration of 0.1-0.3w%;

[0011] (3) injecting a microemulsion-type imbibition flooding agent pre-slug into the oil well, wherein the amount of microemulsion-type imbibition flooding agent is 0.1-0.3w% of the amount of injected steam;

[0012] (4) Implement hydraulic fracturing or fracturing sand control, with the fracture half-length less than 1 / 2 the well spacing;

[0013] (5) Inject steam and then hold the well for 7 to 10 days;

[0014] (6) Start production and continuously monitor the surface activity of the flowback fluid.

[0015] Furthermore, the heavy oil reservoir in step (1) is a heavy oil reservoir with a formation crude oil viscosity greater than 50 mPa.s, a permeability greater than 10 mD, and a depth less than 1800 m.

[0016] Furthermore, the microemulsion-type imbibition oil displacement agent is a single-phase microemulsion composed of 20-35w% of C10-C14 hydrocarbon compounds, 5-25w% of emulsifiers, 0-10w% of cosolvents, 0-3w% of complexing agents, and the balance being water.

[0017] Furthermore, the emulsifier is NP-10, betaine, or comb polymer.

[0018] Furthermore, the comb polymer is obtained by mixing 35-60w% fatty alcohol ether grafted comb polymer, 25-35w% zwitterionic surfactant, 2-5w% perfluoroalkyl polyoxyethylene ether and the balance water, and reacting at 65°C for 2h.

[0019] Furthermore, the cosolvent is an alkyl glycoside.

[0020] Furthermore, the complexing agent is preferably hexamethylenetetramine.

[0021] Furthermore, the variable viscosity slippery water system microemulsion type imbibition oil displacement fracturing fluid is 0.1-0.45w% polyacrylamide emulsion drag reducer + 0.5w% small molecule cationic anti-swelling agent + 0.1-0.3w% microemulsion type imbibition oil displacement agent + 0.5w% SD-2 organic boron crosslinking agent + 0.05w% ammonium persulfate gel breaker.

[0022] Furthermore, the microemulsion type imbibition oil displacement agent pre-slug in step (3) is injected using a 700-1000 type fracturing truck, and the concentration of the microemulsion type imbibition oil displacement agent is 1-5w%.

[0023] Furthermore, the hydraulic fracturing in step (4) refers to the implementation of reservoir transformation by fracturing for low permeability reservoirs with a permeability of less than 100 mD, which converts radial flow into linear flow, increases the effective radius, and reduces the flow rate to achieve the purpose of sand control.

[0024] Furthermore, the fracturing and sand control refers to the formation of short and wide cracks with high conductivity through end-sand removal fracturing for medium and low permeability loose sandstone reservoirs, thereby expanding the sand control radius and improving the conductivity.

[0025] Furthermore, in step (5), the steam injection is directed to the oil layer to inject high-temperature and high-pressure steam of 300-350°C, and the oil layer and crude oil within a considerable distance near the wellbore are heated. The steam dryness is >75%, and the injection volume is 500-2000m 3 The soaking time is mainly determined based on the core imbibition curve and numerical simulation results.

[0026] Furthermore, the continuous monitoring of the surface activity of the flowback fluid in step (6) refers to measuring the surface tension, interfacial tension and microemulsion tracer components of the produced water.

[0027] The method also includes repeating steps (1) to (6) in sequence to perform multiple rounds of throughput mining. BRIEF DESCRIPTION OF THE DRAWINGS

[0028] Figure 1 This is the fracturing operation curve of Well Leng43-Guan11;

[0029] Figure 2 This is the steam injection parameter curve for Well Leng43-Guan11;

[0030] Figure 3 This is the oil production curve of Well Leng43-Guan11;

[0031] Figure 4This is the fracturing construction curve of Well Leng 43-60-558.

[0032] Among them: 1. Oil pressure, unit is MPa; 2. Displacement, unit is m 3 / min; 3. Sand ratio, in %; 4. Pressure, in MPa; 5. Dryness; 6. Daily liquid production, in t; 7. Daily oil production, in t; 8. Water content, in %; 9. Discharge volume, in m 3 / min; 10. Sand transport rate, unit is m 3 / min; 11. Casing pressure, the unit is MPa.

[0033] The beneficial effects of the present invention compared with the prior art are:

[0034] (1) Using microemulsion-type imbibition oil displacement agent as the main carrier, one agent has multiple functions, reduces the types of chemical additives, improves the return rate and water recovery rate of fracturing fluid, and assists in viscosity reduction, oil washing and oil displacement.

[0035] (2) Microemulsion-type imbibition oil displacement agent has the advantages of both water-soluble viscosity reducers and oil-soluble viscosity reducers. It is easy to operate, has good temperature resistance, good viscosity reduction effect, and does not affect demulsification.

[0036] (3) Solve the problems of high steam injection pressure, severe sand production and rapid production decline through fracturing transformation or fracturing sand control methods.

[0037] (4) A microemulsion-type imbibition drive fracturing fluid is used to transform into a viscous slippery water system to solve the problems of difficulty in breaking the guar gum fracturing fluid, serious reservoir damage, poor sand carrying capacity of the slippery water fracturing fluid system, and the need for rapid flowback after fracturing, which leads to complex processes and cold damage.

[0038] (5) Realize the integration of reservoir unblocking, reservoir transformation, fracturing and sand control, viscosity reduction, permeability enhancement and oil displacement, simplify the construction process, and improve the oil production rate and recovery rate. DETAILED DESCRIPTION

[0039] To provide a clearer understanding of the technical features, objectives, and beneficial effects of the present invention, the technical solutions of the present invention are described in detail below with reference to the following specific examples. However, these examples are not to be construed as limiting the scope of the present invention. Unless otherwise specified, the experimental methods employed in the present invention are conventional methods, and the experimental equipment, materials, and reagents used are all commercially available.

[0040] The present invention uses microemulsion-type imbibition oil displacement as the main carrier, replacing conventional viscosity reducers, oil displacement agents and drainage aids, to achieve reservoir protection, viscosity reduction and oil displacement integration, simple operation, good viscosity reduction effect, and no impact on demulsification; through fracturing transformation or fracturing sand control methods, solve the problems of high steam injection pressure, severe sand production, and rapid production decline; adopt a microemulsion-type imbibition oil displacement fracturing fluid viscous slippery water system to solve the problems of difficult gel breaking of guar gum fracturing fluid, severe reservoir damage, poor sand carrying capacity of slippery water fracturing fluid system, and the need for rapid flowback after fracturing, resulting in complex process and cold damage; realize reservoir unblocking-reservoir transformation-fracturing sand control-viscosity reduction-permeability enhancement-oil displacement integration, simplify the construction process, and improve oil production rate and recovery rate. Specifically, the present invention provides an improved fracturing-assisted steam huff-and-puff method for heavy oil production.

[0041] The focus of the present invention is to provide a high-temperature resistant oil-displacing fracturing fluid system and an integrated fracturing and oil-displacing process; on the other hand, it is a process for thermal recovery through auxiliary steam huff and puff after fracturing.

[0042] High-temperature-resistant fracturing fluid systems primarily include variable-viscosity slickwater and microemulsion-type imbibition displacement agents. Variable-viscosity slickwater is composed of associative small-molecule polymers and water. Its viscosity can be modified according to specific needs, allowing it to be used as a fracturing pre-flushing fluid and sand-carrying fluid. Microemulsion-type imbibition displacement agents, on the other hand, are a new type of displacement agent. They can be a system with a "core-shell" structure. Microemulsion-type imbibition agents have droplet sizes ranging from 9nm to 200nm and are a stable thermodynamic system with ultra-low interfacial tension and a high solubilization capacity (solubilization capacity can reach 60%-70%). Due to the small micelle size, oil-wetting properties, and low surface tension of microemulsion-type imbibition displacement agents, compared to conventional surfactants, they absorb less liquid into the reservoir, allowing them to enter micropores and microcracks and be discharged smoothly. Microemulsion-type imbibition displacement agents also possess the ability to self-assemble. This refers to the process by which basic structural units, such as molecules, nanomaterials, and other small or larger-scale substances, spontaneously form thermodynamically stable, structurally defined aggregates with unique properties through non-covalent interactions. Its most significant characteristic is that once assembly begins, it proceeds spontaneously to a desired endpoint and reaches a state of equilibrium, whereby the various structural units spontaneously arrange themselves in an orderly fashion or form complex functional systems, all without the need for external forces. Furthermore, microemulsion-based sorption displacement agents adapt to environmental conditions, forming a system with minimal defects, maximizing functionality.

[0043] At the same time, the complexing agent contained in the microemulsion type osmotic displacement agent is a polycyclic heterocyclic compound, preferably hexamethylenetetramine, which can promote the mutual attraction between molecules with different electrical properties and the heteroatoms on the complexing agent ring, "reinforce" the "core-shell" structure of the microemulsion type osmotic displacement agent, and change the electrical distribution of colloids and asphaltene in crude oil, reducing the attraction between its macromolecular micelles, thereby playing a role in viscosity reduction and dispersion.

[0044] The combination of microemulsion-type imbibition displacement agent and steam injection can not only play the role of reducing the viscosity and displacing heavy oil by the microemulsion-type imbibition displacement agent, but also play its dissolving and dispersing role, thereby improving the thermal efficiency of steam and making the steam sweeping area larger, thereby improving the effect of fracturing and steam huff and puff, and increasing production.

[0045] Example 1

[0046] 35w% of fatty alcohol ether grafted comb polymer, 25w% of hexadecyl hydroxypropyl ethyl sulfobetaine, 2.6% of dodecyl perfluoroalkyl polyoxyethylene ether and 37.4% of water were mixed and reacted at 65°C for 2h to obtain an emulsifier.

[0047] (1) Based on the geological characteristics of heavy oil reservoirs developed by steam stimulation, the formula of the microemulsion type imbibition displacement agent was optimized. The microemulsion type imbibition displacement agent is a single-phase microemulsion composed of 30w% of diene terpenes, 25w% of the above-mentioned emulsifier, 5w% of alkyl saccharide, 1w% of hexamethylenetetramine, and 39w% of water, which has the functions of assisting drainage, reducing viscosity and displacing oil;

[0048] (2) According to the characteristics of the oil reservoir and the difficulties in development, the formula of the microemulsion type imbibition displacement fracturing fluid of the variable viscosity slippery water system is optimized. The formula of the microemulsion type imbibition displacement fracturing fluid of the variable viscosity slippery water system is 0.2w% polyacrylamide emulsion drag reducer + 0.5w% small molecule cationic anti-swelling agent + 0.1w% microemulsion type imbibition displacement agent + 0.5w% SD-2 organic boron crosslinking agent + 0.05w% ammonium persulfate gel breaker, so that the concentration of the microemulsion type imbibition displacement agent is 0.3w%;

[0049] (3) Injecting a microemulsion-type imbibition displacement agent pre-slug into the oil well using a 700 or 1000 type fracturing truck. The concentration of the microemulsion-type imbibition displacement agent is 2.5w%, and the amount of the microemulsion-type imbibition displacement agent is 0.2w% of the steam volume.

[0050] (4) Implement hydraulic fracturing or fracturing for sand control, with the half-length of the fracture less than 1 / 2 of the well spacing; hydraulic fracturing refers to the reservoir transformation of low permeability reservoirs with a permeability of less than 100mD by fracturing, which transforms radial flow into linear flow, increases the effective radius, and reduces the flow rate to achieve the purpose of sand control; fracturing for sand control refers to the formation of short and wide fractures with high conductivity through end-sand removal fracturing in medium and low permeability loose sandstone reservoirs, thereby expanding the sand control radius and improving the conductivity.

[0051] (5) Steam injection: Inject 300℃ high-temperature and high-pressure steam into the oil layer. The oil layer and crude oil within a considerable distance near the wellbore are heated. The steam dryness is >75%, and the injection volume is 1000m 3 The soaking time is mainly determined based on the core imbibition curve and numerical simulation results. In this embodiment, the soaking time is 8 days.

[0052] (6) Start production and continuously monitor the surface activity of the flowback fluid and measure the surface tension and interfacial tension of the produced water.

[0053] Example 2

[0054] NP-10 was used as the emulsifier, and the remaining steps were the same as those in Example 1.

[0055] Example 3

[0056] Betaine was used as the emulsifier, and the remaining steps were the same as those in Example 1.

[0057] Example 4 Cold 43-View 11 Well

[0058] The well is located in the eastern part of the S32 reservoir in the cold 43 block. It was fractured in May 2020. The fractured well section was 1850.6-1882m, 29.5m, and steam stimulation was used after fracturing. During the fracturing process of the well, microemulsion fracturing fluid was used to produce oil. The fracturing fluid was 360m 3 , the proppant is quartz sand and resin sand, a total of 32m 3 , with a burst pressure of 44.2MPa. As of the end of June 2022, a total of 2 rounds of steam stimulation have been carried out, with a cumulative steam injection of 4739m 3 The average steam injection pressure is 17.4MPa, the peak daily oil production after fracturing is 17 tons, the cumulative oil production is 2,148 tons, and the average daily oil production is 6 tons.

[0059] Example 5 Cold 43-60-558 Well

[0060] The well is located in the eastern part of the S32 reservoir in the cold 43 block. It was fractured in January 2022. The fractured well section is 1829.3-1870m, 38.2m, and steam stimulation production is carried out after fracturing. The well was fractured using conventional guar gum system fracturing fluid, with a fracturing fluid of 470m 3 , the proppant is quartz sand and resin sand, a total of 45m 3 , fracture pressure 50.2MPa. After fracturing, steam injection cannot be injected, steam injection pressure is 19.5MPa, cumulative injection 52m 3 , after pumping out the well, nothing comes out, and the fracturing is ineffective.

[0061] The above-described embodiments are only preferred embodiments of the present invention, and are not intended to be all feasible embodiments of the present invention. Any obvious modifications made by a person skilled in the art without departing from the principles and spirit of the present invention should be considered to be included within the scope of protection of the claims of the present invention.

Claims

1. A method for producing heavy oil by microemulsion imbibition flooding and fracturing assisted by steam stimulation, characterized in that: It includes the following steps: (1) In view of the geological characteristics of heavy oil reservoirs developed by steam stimulation, the formula of microemulsion-type imbibition displacement agent is optimized, which has the functions of drainage assistance, viscosity reduction and imbibition displacement. The microemulsion-type imbibition displacement agent is a single-phase microemulsion composed of 20-35w% C10-C14 hydrocarbon compounds, 5-25w% comb polymers, 0-10w% alkyl sugars, 0-3w% complexing agents, and the balance is water; the comb polymer is obtained by mixing 35-60w% fatty alcohol ether grafted comb polymers, 25-35w% zwitterionic surfactants, 2-5w% perfluoroalkyl polyoxyethylene ethers, and the balance is water, and reacting at 65°C for 2h; (2) According to the reservoir characteristics and development difficulties, the formula of the microemulsion type imbibition displacement fracturing fluid for variable viscosity slippery water system is optimized, so that the concentration of the microemulsion type imbibition displacement agent is 0.1-0.3w%, and the microemulsion type imbibition displacement fracturing fluid for variable viscosity slippery water system is 0.1-0.45w% polyacrylamide emulsion drag reducer + 0.5w% small molecule cationic quaternary ammonium salt anti-swelling agent + 0.1-0.3w% microemulsion type imbibition displacement agent + 0.5w% SD-2 organic boron crosslinking agent + 0.05w% ammonium persulfate gel breaker; (3) Injecting a microemulsion-type imbibition flooding agent into the oil well as a pre-slug. The dosage of the microemulsion-type imbibition flooding agent is 0.1-0.3% of the injected steam volume. (4) Implement hydraulic fracturing or fracturing sand control, with the half-length of the fracture less than 1 / 2 of the well spacing. Fracturing sand control refers to the process of forming short and wide fractures with high conductivity through end-sand removal fracturing for medium and low permeability loose sandstone reservoirs, thereby expanding the sand control radius and improving the conductivity; (5) Inject steam, then shut down the well for 7-10 days. Inject steam at 300-350℃ high temperature and high pressure into the oil layer. The oil layer and crude oil within a considerable distance near the wellbore are heated. The steam dryness is >75%, and the gas injection volume is 500-2000m 3 The soaking time is mainly determined based on the core imbibition curve and numerical simulation results; (6) Start production and continuously monitor the surface activity of the flowback fluid.

2. The method for producing heavy oil by microemulsion imbibition flooding and fracturing assisted by steam stimulation as claimed in claim 1, characterized in that: The heavy oil reservoir in step (1) is a heavy oil reservoir with a formation crude oil viscosity greater than 50 mPa.s, a permeability greater than 10 mD, and a depth less than 1800 m.

3. The method for producing heavy oil by microemulsion imbibition flooding and fracturing assisted by steam stimulation as claimed in claim 1, wherein: The complexing agent is hexamethylenetetramine.

4. The method for producing heavy oil by microemulsion imbibition flooding and fracturing assisted by steam stimulation as claimed in claim 1, wherein: The microemulsion type imbibition oil displacement agent pre-slug in step (3) is injected using a 700-1000 type fracturing truck, and the concentration of the microemulsion type imbibition oil displacement agent is 1-5w%.

5. The method for producing heavy oil by microemulsion imbibition flooding and fracturing assisted by steam stimulation as claimed in claim 1, characterized in that: The hydraulic fracturing in step (4) refers to the reservoir transformation by fracturing of low permeability reservoirs with a permeability of less than 100 mD, which converts radial flow into linear flow, increases the effective radius, and reduces the flow rate to achieve the purpose of sand control.

6. The method for producing heavy oil by microemulsion imbibition flooding and fracturing assisted by steam stimulation as claimed in claim 1, wherein: The continuous monitoring of the surface activity of the flowback fluid in step (6) refers to measuring the surface tension, interfacial tension and microemulsion tracer components of the produced water.

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