Microbial biosurfactant-enhanced oil recovery

Abstract

The present application relates to the technical field of oil exploitation, in particular to a method for enhancing cold production of heavy oil based on foam oil of microbial biogenic gas. In the method, an amphiphilic surfactant and a gas-producing functional bacteria nutrient solution are injected into a predetermined pore volume plug, and in a specific aqueous phase environment, the functional bacteria are excited to release CO2 and CH4 mixed microbubbles in situ; during the well soaking period, the surfactant specifically adsorbs heavy components such as heavy oil asphaltene, crosslinks at the gas-liquid interface to build a composite rigid membrane, and forms a stable gas-liquid-foam three-phase foam oil system in situ; finally, the pressure drop is carried out. The method uses the rigid membrane to effectively plug high-permeability channels, suppress gas slip and gas channeling, and relies on the dual kinetic mechanisms of CO2 dissolution viscosity reduction and CH4 internal pressure boosting of the free microbubbles, which greatly expands the cold production swept volume and significantly improves the residual oil recovery.

Description

Technical Field

[0001] This invention relates to the field of petroleum extraction technology, and more specifically, to a foam-enhanced cold extraction method for heavy oil based on microbial self-generating gas. Background Technology

[0002] After long-term thermal recovery development through methods such as huff and puff or displacement, heavy oil reservoirs generally enter a depletion stage characterized by high water cut and low formation pressure. With the large-scale development of gas channeling pathways and the continuous decline in the oil-gas ratio during the later stages of thermal recovery, formation energy is severely depleted, and a large amount of remaining oil is bound by capillary forces in the micropores of the matrix, making it difficult to effectively utilize conventional extraction methods. Therefore, utilizing microbial cold recovery technology to replace or supplement traditional thermal recovery has become an important research direction for improving the recovery rate of heavy oil reservoirs in the later stages.

[0003] However, existing heavy oil microbial cold recovery technologies still face the dual technical bottleneck of difficulty in simultaneously achieving viscosity reduction and pressurization in practical engineering applications. Conventional microbial enhanced oil recovery (DEOR) technologies mainly rely on functional strains to secrete biosurfactants or degrade crude oil macromolecules in the formation, with their core function focusing on in-situ emulsification and wettability adjustment at the oil-water interface. This single emulsification and viscosity reduction mechanism often results in extremely low deep sweep efficiency for depleted reservoirs with severe formation pressure deficits due to a lack of sufficient flow-driven elastic energy, making it difficult to achieve effective crude oil displacement.

[0004] To compensate for formation energy deficits, engineering practices often employ methods such as injecting exogenous gases (e.g., carbon dioxide, nitrogen) into the formation or utilizing in-situ fermentation of gas-producing bacteria to generate biogas (e.g., carbon dioxide, methane). However, due to the extremely complex porous underground environment and the extremely low viscosity of the gas phase, severe mobility imbalances exist between the gas and liquid phases in heavy oil reservoirs. Driven by the pressure differential of the production well, free gas is highly susceptible to violent gas slippage and channeling along water-drive dominant channels, fractures, or high-permeability zones during migration. This sudden channeling not only causes biogas to bypass the high-viscosity oil-rich area and overflow directly from the production well, resulting in gas loss, but also causes the hard-won formation elastic energy to dissipate rapidly in a very short time, leaving a large amount of residual oil trapped in the micropores.

[0005] Therefore, how to effectively control gas migration behavior in porous media of deep oil reservoirs, suppress gas slippage and flow channeling, and efficiently intercept and anchor the in-situ generated biogas within the heavy oil system so as to transform it into stable and long-term underground driving energy is a technical challenge that urgently needs to be overcome in the field of heavy oil cold extraction and enhanced oil recovery. Summary of the Invention

[0006] The purpose of this invention is to provide a foam oil-enhanced cold production method for heavy oil based on microbial self-generated gas, in order to solve the technical problems mentioned in the background art, such as the extreme lack of formation driving energy in the later stage of cold production of heavy oil reservoirs, and the easy induction of gas slippage and gas channeling due to the imbalance of mobility ratio during conventional gas injection or biogas production, resulting in the inability to effectively utilize residual oil and rapid energy dissipation.

[0007] To achieve the above objectives, this invention provides a foam oil-enhanced heavy oil cold recovery method based on microbial self-generating gas, comprising the following steps: S1. Slug Injection and Deep Advancement: Slug injection is performed into the target heavy oil layer at a predetermined pore volume ratio. The injection system contains a mixture of amphiphilic surfactants, gas-producing bacterial solution, and nutrient solution. Subsequently, the injected displacement fluid pushes the mixture into the deep porous medium of the reservoir, forming a pre-working slug. S2. In-situ environmental activation and slow-release gas production: Monitor and adjust the formation water phase environmental parameters, and directionally stimulate the enzymatic reaction of gas-producing functional bacteria in deep formations, so that they can slowly release mixed gas microbubbles containing carbon dioxide and methane in the pores at a predetermined rate. S3. Three-phase steady-state coupling and well-blocking control: The wellhead is sealed to block the well, so that the generated microbubbles, amphiphilic surfactants and the heavy components inherent in the heavy oil undergo interfacial cross-linking in the micropore throat, and a gas-liquid-foam three-phase steady-state foam oil system is constructed in situ; the bottom hole pressure recovery curve is monitored in real time, and when the pressure gradient tends to be stable and reaches the preset threshold, it is determined that the three-phase coupling has reached dynamic equilibrium. S4. Controlled pressure drainage and dual-effect drive: The well is opened and drained using a preset constant pressure gradient method. The mixed gas is excited in the foam structure and the internal pressurization dual dynamic mechanism is used to drive the viscosity-reduced foam oil to overcome capillary resistance, peel off and precipitate from the pore throat and produce it to the surface.

[0008] As a preferred embodiment of the technical solution of the present invention, in S1, the amphiphilic surfactant is a betaine-type amphiphilic surfactant, and its mass fraction in the mixture is controlled at 0.2%~0.8%.

[0009] As a preferred embodiment of the present invention, in step S1, the gas-producing functional bacteria nutrient solution contains sodium formate or sodium acetate as a gas-producing precursor, and the mass fraction of the gas-producing precursor is 1% to 3%.

[0010] As a preferred embodiment of the technical solution of the present invention, in step S2, adjusting the formation water phase environment parameters specifically involves maintaining the pH value of the formation system between 6.5 and 7.5, and controlling the formation temperature between 30°C and 55°C.

[0011] In this invention, a betaine-type amphiphilic surfactant, pre-injected into a deep porous medium, rapidly accumulates its amphiphilic molecules at the gas-liquid micro-interface during the in-situ slow-release gas production (CO2 and CH4) by microorganisms. More importantly, the lipophilic end of the surfactant molecule can adsorb and anchor high-molecular-weight heavy components (such as asphaltenes and gums with rigid polycyclic structures) in heavy oil. After being introduced into the bubble interface, these heavy components co-crosslink with the surfactant, constructing a spatial network composite rigid film with extremely high mechanical strength and viscoelasticity on the microbubble surface.

[0012] This in-situ generated special composite rigid liquid film alters the thermodynamic instability of conventional bubbles, which are prone to coalescence and collapse. It significantly extends the half-life of bubbles in the porous reservoir medium, forming an extremely stable non-Newtonian foam oil fluid. This fluid exhibits rheological characteristics in porous media: a surge in flow resistance at large pores and easy elastic deformation through small micropores. This enables autonomous diversion of deep fluid flow, effectively blocking high-permeability water channeling during the later stages of thermal recovery and suppressing gas slippage and sudden gas channeling.

[0013] CO2, as a readily soluble gas, diffuses deeply into the crude oil under the long-term locking state of the interfacial composite membrane, causing a significant volume expansion and viscosity reduction in heavy oil. CH4, as a poorly soluble gas, is firmly wrapped in the composite rigid membrane in the form of free microbubbles. Guided by the well opening pressure drop, it acts like a dense micro-compression spring, providing a continuous and uniform internal pressurization elastic driving force for the stripping of residual crude oil.

[0014] Compared with the prior art, the beneficial effects of the present invention are as follows: This foam oil-enhanced heavy oil cold recovery method based on microbial self-generated gas overcomes the technical shortcomings of conventional microbial gas production, which is prone to slippage and loss, by constructing a rigid foam oil composite liquid film with surfactant-heavy component crosslinking in situ. It effectively intercepts and transforms the easily lost gas into a stable, elastic oil displacement carrier, significantly improving the sweep range of heavy oil cold recovery in micropores.

[0015] Secondly, by utilizing the heterogeneity of the endogenous metabolic gas phase, relying on the viscosity reduction driven by dissolved CO2 and the internal pressurization mechanism of free microbubbles of CH4, the final foam oil system has an apparent viscosity lower than that of the original heavy oil and higher elastic energy, effectively solving the engineering pain point that single viscosity reduction or single gas injection cannot simultaneously meet the needs of deep crude oil displacement.

[0016] Meanwhile, it exhibits strong green and low-carbon adaptability, significantly reduces process costs, and avoids the traditional model of forcibly injecting external gas using ground-based high-pressure equipment. Utilizing in-situ slow-release gas production by microorganisms, the process boasts low energy consumption and minimal carbon emissions. This technology provides a highly economical and environmentally friendly new approach for enhanced cold recovery of heavy oil reservoirs with high water content and energy deficits in the later stages of thermal recovery development. Attached Figure Description

[0017] Figure 1 This is an overall flowchart of an embodiment of the present invention. Detailed Implementation

[0018] The technical solutions in the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0019] In the following examples and comparative examples, unless otherwise specified, the raw materials, reagents and equipment used are all commercially available products in the art or prepared by conventional methods.

[0020] Experimental materials and basic conditions: Experimental oil: Dehydrated and degassed crude oil from a heavy oil block, with an apparent viscosity of 12500 mPa·s at 50℃ and a total mass fraction of asphaltene and gums of 28.5%. Methanogenic bacterial solution: A mixed bacterial solution of methanogenic bacteria and fermentative bacteria enriched from background water samples of the target reservoir, with an effective viable count ≥1.0 × 10⁻⁶. 8 CFU / mL. Physical simulation equipment: High-temperature and high-pressure three-dimensional core-filled sand-tube displacement system (sand-filled tube dimensions: diameter 3.8cm, length 30cm, water permeability 1500×10⁻⁶). -3 μm 2 Simulated porosity 32%); high temperature and high pressure microscopic visualization glass etching model; high pressure PVT property analyzer.

[0021] The enhanced heavy oil cold production system involved in the embodiments of the present invention includes a surface mixing pump injection vehicle (as a mixing injection module), a downhole fiber optic temperature and pressure measuring probe (as a downhole environment monitoring module), and a wellhead automated throttling and pressure control device (as a pressure monitoring and drainage module).

[0022] Example 1: A foam oil-enhanced heavy oil cold extraction method based on microbial self-generating gas, see [link to example]. Figure 1 The steps are as follows: S1. Slug Injection and Deep Advancement: The sand-filled pipe is evacuated and saturated with simulated formation water. After measuring the pore volume (PV), heavy oil is saturated. A premixing system is prepared using a mixing injection module, containing 0.2% by mass of octadecyl dimethyl sulfopropyl betaine (betaine-type amphiphilic surfactant), 1% by mass of sodium formate (gas-producing precursor), and the remainder being gas-producing bacterial solution. Slug injection is performed into the porous media model at 0.2 PV. Subsequently, 0.05 PV of simulated formation water is injected as a displacement fluid via the displacement fluid injection line to push the mixture into the deep porous media, forming the pre-working slug.

[0023] S2. In-situ Environmental Activation and Slow-Release Gas Production: The aqueous environment parameters were monitored and adjusted using a downhole environmental monitoring module to ensure the pH value of the system was maintained at 6.5 and the temperature was controlled at 30℃. Under these environmental conditions, the enzymatic reaction of gas-producing bacteria within the pores was directionally activated, and sodium formate was used as a substrate to slowly release microbubbles containing a mixture of carbon dioxide and methane.

[0024] S3. Three-phase steady-state coupling and well-blocking control: Well-blocking is performed at both ends of the closed model, with a blocking period of 15 days. During the blocking period, the generated microbubbles, amphiphilic surfactants, and inherent heavy components (asphaltite / colloids) in the heavy oil undergo interfacial cross-linking within the pore throat. Specifically, the lipophilic groups of the amphiphilic surfactants specifically adsorb the asphaltenes and colloidal heavy components in the heavy oil, constructing a dense spatial network composite rigid film at the microbubble solid-liquid interface, which encapsulates the free microbubbles. The spatial network composite rigid film prolongs the half-life of microbubbles in the porous medium, causing the foam oil system to exhibit non-Newtonian fluid characteristics of increased flow resistance in large pores and elastic deformation penetration in small pore throats, thereby blocking high-permeability water channeling and inhibiting gas slippage and gas channeling. A gas-liquid-foam three-phase steady-state coexistence foam oil system is constructed in situ; the pressure recovery curve is monitored in real time by the pressure monitoring and drainage module, and the three-phase coupling is determined to have reached dynamic equilibrium when the pressure gradient tends to stabilize.

[0025] S4. Controlled Pressure Drainage and Dual-Effect Drive: Relying on the pressure monitoring and drainage module, the outlet end is opened for drainage using a preset constant pressure drop gradient method (set to 0.3MPa / d pressure drop). The mixed gas is activated in the foam structure through a dual mechanism of dissolved gas drive and internal pressurization. Specifically, carbon dioxide in the mixed gas diffuses into the crude oil under the state of interfacial cross-linking, causing the heavy oil volume to expand and viscosity to decrease. Methane in the mixed gas is wrapped in the foam structure in the form of free microbubbles, releasing the internal pressurization elastic energy, which drives the viscosity-reduced foam oil to overcome capillary resistance and be separated and produced from the pore throat.

[0026] Example 2: The steps are exactly the same as in Example 1, the only difference being the parameters: In S1, the mass fraction of betaine-type amphiphilic surfactant is 0.5%, and the mass fraction of sodium formate is 2%. In S2 and S3, the pH of the system is adjusted to 7.0, and the temperature is controlled at 45℃. In S4, the preset constant pressure drop gradient controls the pressure drop rate to 0.4MPa / d.

[0027] Example 3: The steps are exactly the same as in Example 1, the only difference being the parameters: In S1, the mass fraction of betaine-type amphiphilic surfactant is 0.8%, and the mass fraction of sodium formate is 3%. In S2 and S3, the pH value of the system is adjusted to 7.5, and the temperature is controlled at 55℃. In S4, the preset constant pressure drop gradient controls the pressure drop rate to 0.5MPa / d.

[0028] Comparative Example 1: The steps are the same as in Example 2, except that: In the mixed system prepared by S1, the mass fraction of betaine-type amphiphilic surfactant is 0.1%.

[0029] Comparative Example 2: The steps are the same as in Example 2, except that: In the mixed system prepared by S1, the mass fraction of betaine-type amphiphilic surfactant is 1.2%.

[0030] Comparative Example 3: The steps are the same as in Example 2, except that: The temperature parameters in S2 and S3 are both controlled at 20℃.

[0031] Comparative Example 4: The steps are the same as in Example 2, except that: The temperature parameters in S2 and S3 are both controlled at 65℃.

[0032] Comparative Example 5: Without mixing the system or simmering the well, 0.2 PV of formation water and 0.2 PV of nitrogen under standard conditions were injected alternately at a rate of 0.5 mL / min, and then discharged directly according to the pressure drop gradient of S4.

[0033] Comparative Example 6: The steps are basically the same as in Example 2, except that: The S1 mixture system does not contain any betaine-type amphiphilic surfactants; it relies solely on the functional bacterial solution and gas-generating precursor for S3 gas-generating foaming.

[0034] For each of the above embodiments and comparative examples, during and after the S4 drainage process, the gas channeling breakthrough time (PV, characterizing the gas channeling resistance), foam oil half-life (days), system viscosity reduction rate (%), and recovery rate improvement (%OOIP) were simultaneously measured. The test results are detailed in Table 1.

[0035] Table 1. Statistical table of technical effect verification data for examples and comparative examples:

[0036] As shown in Table 1, the data from Examples 1-3 indicate that within the concentration range of 0.2% to 0.8%, the gas channeling breakthrough time is significantly delayed to 0.75-0.88 PV, with a half-life exceeding 18 days. Microscopic physical model observations confirm that at this concentration, the amphiphilic molecules form a continuous, rigid composite liquid film with the heavy components of the crude oil, achieving effective fluid diversion. However, at excessively low concentrations (Comparative Example 1, 0.1%), film formation is impossible, resulting in severe early gas channeling; at excessively high concentrations (Comparative Example 2, 1.2%), multiple emulsification occurs, and the surge in resistance causes fluid to escape along high-permeability channels (breakthrough time drops to 0.38 PV).

[0037] Secondly, comparing the examples with Comparative Examples 3 and 4, it can be seen that 30℃~55℃ can well match the thermodynamic stability range of the gas-producing enzymatic activity and the physical composite liquid film. At 20℃, the gas production is extremely low due to metabolic inhibition, and the internal pressurization is insufficient; while at 65℃, the composite rigid film fails to pyrolyze, the foamed oil collapses within 2.1 days, and gas channeling occurs extremely rapidly (0.18PV breakthrough).

[0038] A comparison of Examples 1-3 with Comparative Examples 5 and 6 shows that conventional physical gas injection (Comparative Example 5) is highly prone to severe slippage, with gas channeling occurring as early as 0.12 PV; while conventional simple biological gas generation (Comparative Example 6), due to the lack of interfacial cross-linking between surfactants and heavy components, results in bubbles that cannot maintain mechanical strength, with a half-life of only 1.5 days and rapid subsequent energy dissipation. This invention successfully seals microscopic water / gas channeling pathways in pore throats by constructing an in-situ gas-liquid-foam three-phase coupled steady-state system.

[0039] The foregoing has shown and described the basic principles, main features, and advantages of the present invention. Those skilled in the art should understand that the present invention is not limited to the above embodiments. The embodiments and descriptions in the specification are merely preferred examples of the present invention and are not intended to limit the invention. Various changes and modifications can be made to the present invention without departing from its spirit and scope, and all such changes and modifications fall within the scope of the present invention as claimed. The scope of protection of the present invention is defined by the appended technical solutions and their equivalents.

Claims

1. A foam-enhanced heavy oil cold extraction method based on microbial self-generating gas, characterized in that, Includes the following steps: S1: Slug injection is performed into the target heavy oil layer at a predetermined pore volume ratio. The injection system is a mixture containing amphiphilic surfactants, gas-producing bacterial solution, and nutrient solution. Subsequently, the injected displacement fluid pushes the mixture into the deep porous medium of the reservoir to form a pre-working slug. S2: Monitor and adjust formation water phase environmental parameters, and directionally stimulate the enzymatic reaction of gas-producing bacteria in deep formations, so that they can slowly release microbubbles containing a mixture of carbon dioxide and methane in the pores. S3: The wellhead is sealed to allow the generated microbubbles, amphiphilic surfactants and heavy components inherent in the heavy oil to undergo interfacial cross-linking within the micropore throat, forming a gas-liquid-foam three-phase steady-state foam oil system in situ; the bottom-hole pressure recovery curve is monitored in real time, and when the pressure gradient tends to be stable and reaches the preset threshold, it is determined that the three-phase coupling has reached dynamic equilibrium. S4: The well is opened and drained using a preset constant pressure gradient method. The mixed gas is used to drive the dissolved gas in the foam structure and the internal pressurization dual dynamic mechanism to drive the viscosity-reduced foam oil to be separated and precipitated from the pore throat and produced to the surface.

2. The method for enhancing heavy oil cold extraction based on microbial self-generating foam oil according to claim 1, characterized in that, In S1, the amphiphilic surfactant is a betaine-type amphiphilic surfactant, and its mass fraction in the mixture is controlled at 0.2% to 0.8%.

3. The method for enhancing heavy oil cold extraction based on microbial self-generating foam oil according to claim 1, characterized in that, In S1, the gas-producing functional bacteria nutrient solution contains sodium formate or sodium acetate as a gas-producing precursor, and the mass fraction of the gas-producing precursor in the mixture is 1% to 3%.

4. The method for enhancing the cold recovery of heavy oil based on microbial self-generating foam oil according to claim 1, characterized in that, In S2, adjusting the formation water phase environment parameters specifically involves maintaining the pH value of the formation system between 6.5 and 7.5, and controlling the formation temperature between 30℃ and 55℃.

5. The method for enhancing heavy oil cold extraction based on microbial self-generating foam oil according to claim 1, characterized in that, In step S3, the specific process of interfacial cross-linking occurring within the micropore throat is as follows: The lipophilic groups of the amphiphilic surfactant specifically adsorb asphaltenes and gum heavy components in heavy oil, constructing a dense spatial network composite rigid film at the microbubble solid-liquid interface, and encapsulating the free microbubbles.

6. The method for enhancing heavy oil cold extraction based on microbial self-generating foam oil according to claim 5, characterized in that, The spatial network composite rigid membrane prolongs the half-life of microbubbles in porous media, enabling the foam oil system to exhibit non-Newtonian fluid characteristics, such as increased flow resistance when encountering large pores and elastic deformation penetration when encountering small pore throats, thereby blocking highly permeable water channeling channels and inhibiting gas slippage and gas channeling.

7. The method for enhancing heavy oil cold extraction based on microbial self-generating foam oil according to claim 1, characterized in that, In S4, the specific manifestations of dissolved gas drive and internal pressurization are as follows: Carbon dioxide in the mixed gas diffuses into the crude oil under the cross-linked state of the interface, causing the heavy oil to expand in volume and decrease in viscosity. Methane in the mixed gas is wrapped in the foam structure in the form of free microbubbles, releasing the internal pressure-boosting elastic energy.

8. The method for enhancing heavy oil cold extraction based on microbial self-generating foam oil according to claim 1, characterized in that, In S4, the preset constant pressure drop gradient specifically controls the pressure drop rate to be between 0.3 MPa / d and 0.5 MPa / d.

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