A biological method to enhance CO2 geological sequestration

Abstract

This invention discloses a biological method for improving CO2 geological sequestration, comprising the following steps: injecting surfactant-producing microorganisms and CO2 into a geological reservoir; the geological reservoir, used for CO2 sequestration, is a geological space containing formation water, including at least one of saline aquifers, depleted or abandoned oil and gas reservoirs; the surfactant-producing microorganisms metabolize to produce biosurfactants; the biosurfactants are used to reduce the surface tension of the formation water, promoting the dissolution of CO2 in the formation water, thereby sequestering the injected CO2 in a dissolved state. This invention utilizes the surfactant substances produced by surfactant-producing bacteria to reduce gas-liquid surface tension and promote CO2 dispersion into the aqueous phase, thereby improving the dissolution and sequestration efficiency of CO2 in saline aquifers. Given the enormous carbon emission reduction pressure faced by my country's cement, steel, and petrochemical industries, this technology has broad application prospects.

Description

Technical Field

[0001] This invention belongs to the field of CO2 geological sequestration, and particularly relates to a biological method for enhancing CO2 geological sequestration. Background Technology

[0002] Carbon capture and storage (CCS) is considered an effective means of achieving direct carbon reduction as a large-scale greenhouse gas emission reduction technology. Geological storage is an important approach to achieving permanent emission reduction. Currently, sites suitable for CO2 geological storage mainly include deep saline aquifers in sedimentary basins, depleted or abandoned oil and gas fields, abandoned coal seams, and mined-out areas. These geological reservoirs mostly contain large amounts of saline water and have stable geological conditions, making them the main space for large-scale CO2 geological storage with huge potential. However, CO2 mainly exists in a supercritical form during geological storage, and it can abruptly change into a gaseous or liquid state under different temperatures and pressures, easily leaking into the surface or groundwater through fractures or caprocks, causing environmental pollution and ecological damage. Dissolving large amounts of CO2 in saline water or reacting with diagenetic ions to form carbonate minerals can effectively reduce the risk of leakage and improve the safety and stability of storage. Existing technologies for enhancing CO2 dissolution include patent TWM661647U, "Carbon Sequestration Device Applied to Saline Aquifers," which uses alternating water-gas injection to increase the proportion of residual gas and the dissolution and sequestration mechanism; patent CN115076594B, "A Carbon Dioxide Sequestration Method," which converts liquid CO2 into CO2 hydrate in low-temperature, high-pressure seawater to improve stability; and patent CN102504789B, "A Bio-based Lipopeptide Surfactant for Enhancing Oil Recovery," which adds bio-based lipopeptide surfactants during oil extraction to reduce oil viscosity and increase recovery. However, these methods suffer from high costs, stringent conditions, and difficult construction. The purpose of this invention is to overcome the shortcomings of existing technologies and propose a biological method for enhancing CO2 geological sequestration, enabling more CO2 injected into depleted oil and gas fields or deep saline reservoirs to dissolve in the saline water, thereby achieving CO2 sequestration while improving sequestration safety. Summary of the Invention

[0003] The purpose of this invention is to provide a biological method for improving CO2 geological sequestration. This method can reduce the surface tension of saline water, allowing more CO2 injected into depleted oil and gas fields or deep saline water layers to dissolve in the saline water, thereby increasing the rate of saline water layer dissolution and sequestration. This results in most of the CO2 injected into the saline water layer existing in the form of dissolved CO2, enhancing the stability of sequestration and reducing the risk of leakage.

[0004] To achieve the above objectives, the present invention adopts the following technical solution:

[0005] A biological method for enhancing CO2 geological sequestration includes the following steps:

[0006] Inject surfactant-producing microorganisms and CO2 into geological reservoirs;

[0007] The geological reservoir used for CO2 sequestration is a geological space containing formation water, including at least one of saline aquifers, depleted or abandoned oil and gas reservoirs.

[0008] The surfactant-producing microorganisms metabolize to produce biosurfactants;

[0009] The biosurfactant is used to reduce the surface tension of formation water, promote the dissolution of CO2 in formation water, and encapsulate the injected CO2 in a dissolved form.

[0010] Preferably, CO2 and surfactant-producing microorganisms are injected into the geological reservoir through injection wells connected to surface facilities and the geological reservoir.

[0011] Preferably, the surfactant-producing microorganism is a microorganism capable of producing glycolipid or lipopeptide biosurfactants, and can adapt to high-temperature, high-pressure, and high-salt environments. The main function of the surfactant-producing microorganism in this invention is to reduce the surface tension of saline water by utilizing the biosurfactants produced by its metabolism, thereby promoting CO2 dissolution in the saline water and improving the safety and stability of the storage. Therefore, any microorganism capable of surviving in geological reservoir environments and producing surfactants can achieve the objectives of this invention.

[0012] Preferably, the high temperature, high pressure, and high salinity environment is an environment with a mineralization degree >1g / L, a pressure of 8-20MPa, and a temperature of 35-75℃.

[0013] Preferably, the glycolipid biosurfactant includes at least one of rhamnolipid, trehalose ester, and sophorolipid; the lipopeptide biosurfactant includes at least one of lipopeptide, surfactant, myxobin, and polymyxin.

[0014] Preferably, when the geological reservoir is a depleted or abandoned oil and gas reservoir, crude oil extraction can be accelerated and crude oil recovery rate can be increased.

[0015] Another object of the present invention is to provide a simulation test method for verifying the aforementioned biological method for enhancing CO2 geological sequestration.

[0016] A simulation test method includes the following steps:

[0017] S1, the surfactant-producing microorganisms are revived and cultured to obtain bacterial solution;

[0018] S2, mix the bacterial solution and the saline solution evenly, and place them in an autoclave;

[0019] S3, CO2 is injected to raise the pressure inside the autoclave to the preset pressure, simulating the temperature, pressure and types and concentrations of ions in the saline water layer. The evolution of the concentration of dissolved CO2 in the saline water over time is used to characterize the amount of dissolved CO2 in the saline solution, and the carbon content is compared with that under conditions with and without surfactant-producing strains.

[0020] Preferably, in step S1, the surfactant-producing microorganism is a microorganism capable of producing glycolipid or lipopeptide biosurfactants, and can adapt to high-temperature, high-pressure, and high-salt environments. The main function of the surfactant-producing microorganism in this invention is to reduce the surface tension of saline water by utilizing the biosurfactants produced by the metabolism of surfactant-producing microorganisms, promoting CO2 dissolution in saline water, and improving the safety and stability of the sequestration. Therefore, any microorganism capable of surviving in geological reservoir environments and producing surfactants can achieve the purpose of this invention. Preferably, the high-temperature, high-pressure, and high-salt environment is an environment with a mineralization >1 g / L, a pressure of 8–20 MPa, and a temperature of 35–75°C. Preferably, the glycolipid biosurfactants include at least one of rhamnolipid, trehalose, and sophorolipid; the lipopeptide biosurfactants include at least one of lipopeptides, surfactants, myxobin, and polymyxin.

[0021] Preferably, in step S1, the recovery and culture conditions are: Luria-Bertani medium, cultured on a shaker at 37°C and 170 r / min for 36-48 h.

[0022] Preferably, in step S1, the surfactant-producing strain is taken and inoculated into sterilized Luria-Bertani medium, and revived in a shaker at 37°C and 170 r / min; then 2% of the revived bacterial solution is inoculated into sterilized Luria-Bertani medium and cultured in a shaker at 37°C and 170 r / min for 48 h to obtain the bacterial solution.

[0023] Preferably, the Luria-Bertani medium is pH 7.0 and sterilized at 121°C for 20 min.

[0024] Preferably, OD is measured and recorded every 12 hours during resuscitation and culture. 600 The final bacterial culture OD value, 600 >0.8, and the number of microorganisms in the bacterial culture was determined by flow cytometry >10. 8 cells / ml.

[0025] Preferably, in step S2, the saline solution is saline water taken from a saline layer at a depth of 800-2000m, and its mineralization is >1g / L.

[0026] Preferably, in step S2, the volume ratio of the bacterial solution to the saline solution is 0.1 to 1.

[0027] Preferably, in step S3, the saline aquifer is a geological structure at a depth of 800-2000m underground.

[0028] Preferably, in step S3, the conditions inside the autoclave are: temperature: 35–75°C; pressure: 8–20 MPa; time: 5–30 days; CO2 concentration >90%.

[0029] The suitable geological reservoir depth for CO2 sequestration is 800–2000 m. Within this depth range, the reservoir temperature is 35–75 °C, the pressure is 8–20 MPa, and the salinity is >1 g / L, representing a high-temperature, high-pressure, and high-salt environment. In some preferred embodiments, the temperature, pressure, and types and concentrations of ions in the saline water of the geological reservoir are simulated in a laboratory using a high-pressure reactor. Four sets of simulation experiments are designed to verify the effectiveness of the surfactant-producing strains. The first set uses the surfactant-producing strain Rha-T; the second set uses the surfactant-producing strain Rha-S; the third set uses rhamnolipin standards; and the fourth set is a control group without the addition of surfactant-producing strains.

[0030] Preferably, the saline solution used in the three sets of experiments was simulated saline water prepared according to the saline water from a 1000m deep saline layer (per 1L of deionized water: NaCl 32.510g, CaCl2 2.331g, KCl 1.341g, MgCl2 0.475g, NaNO3 4.11mg, Na2SO4 226.31mg), with a mineralization of 36.89g / L. The reaction verification temperature was 50℃, the pressure was 10MPa, and the time was 30 days; the CO2 concentration was >90%. During the experiment, the pH and OD of the reaction solution were measured. 600 The concentration of dissolved CO2 is used to characterize the amount of dissolved CO2 in saline solution by measuring the evolution of dissolved CO2 concentration over time, and to compare the carbon content under conditions with and without surfactant-producing strains.

[0031] The principle of this method is as follows:

[0032] The surface tension of water is primarily caused by intermolecular forces, including van der Waals forces and hydrogen bonds. Due to the strong hydrogen bonds between water molecules, they are densely packed at the surface of the liquid phase, enhancing intermolecular interactions. This increased force leads to a greater attraction between surface molecules and internal molecules, resulting in increased surface tension and a concave liquid surface. Similar to the gas-liquid interface during CO2 dissolution, water molecules at the liquid surface experience a greater attraction from bulk molecules than CO2 molecules. This asymmetry causes surface water molecules to spontaneously enter the bulk liquid, leading to surface tension at the gas-liquid interface. The presence of surface tension limits the large-scale entry of CO2 into the aqueous phase. Biosurfactants are surface-active compounds produced by microorganisms, typically containing both hydrophilic and hydrophobic groups. When a surfactant is added to saline water, these surface-active chemical molecules preferentially adsorb onto the liquid surface, with hydrophilic groups facing the water and hydrophobic groups facing the air or incompatible phase. This directional arrangement on the liquid surface alters the original arrangement of water molecules on the liquid phase surface, significantly reducing surface tension and enhancing the diffusion of CO2 into the liquid phase, allowing more CO2 to enter the aqueous phase, as shown in equation (1). Most of the CO2 entering the aqueous phase exists as free CO2 molecules, while a small amount reacts with water to form carbonic acid, as shown in equation (2). At this point, the density of the saline water containing a large amount of dissolved CO2 increases, causing convection in the aqueous phase. This allows the dissolved CO2 to migrate downwards and deposit at the bottom, achieving stable storage and reducing the risk of leakage.

[0033] CO2(g)→CO2(aq) ⑴

[0034] CO2(aq)+H2O(l)→H2CO3(aq) ⑵

[0035] Beneficial effects: Compared with the prior art, the present invention has the following significant advantages:

[0036] 1. A surfactant-producing strain that can maintain high activity under high temperature, high pressure, and high salinity conditions. It can produce biosurfactants, which can significantly reduce the surface tension between the CO2 phase and the aqueous phase, effectively promote the dissolution of CO2, rapidly increase the concentration of free CO2 molecules in the solution, and improve the rate and amount of dissolution and sequestration of the saline layer.

[0037] 2. Surfactant-producing strains ensure that the CO2 injected into the brine layer exists in a dissolved form, enhancing the stability of the sequestration and increasing the concentration of dissolved CO2 in the aqueous phase. Attached Figure Description

[0038] Figure 1 This is a diagram illustrating the mechanism of action of biosurfactants.

[0039] Figure 2This is a method for detecting the concentration of dissolved CO2 in the system;

[0040] Figure 3 The evolution of dissolved CO2 concentration in the saline aquifer over time in the presence of Rha-T, Rha-S, and rhamnolipin standards, and its comparison with saline aquifers without microorganisms;

[0041] Figure 4 HCO3 sequestered in the saline aquifer when Rha-T, Rha-S, and rhamnolipid standards are present - The evolution of concentration over time and its comparison with saline water without microorganisms. Detailed Implementation

[0042] The present invention will be further explained below with reference to the accompanying drawings and embodiments.

[0043] The present invention provides a biological method for enhancing CO2 geological sequestration, comprising the following steps:

[0044] Inject surfactant-producing microorganisms and CO2 into geological reservoirs;

[0045] Geological reservoirs are used to seal CO2 and are geological spaces containing formation water, including at least one of saline aquifers, depleted or abandoned oil and gas reservoirs;

[0046] Surfactant-producing microorganisms produce biosurfactants through metabolism.

[0047] Biosurfactants are used to reduce the surface tension of formation water, enhance the physical dissolution of CO2, and improve the safety and stability of sequestration.

[0048] CO2 and surfactant-producing microorganisms are injected into the geological reservoir through injection wells connected to surface facilities and the geological reservoir.

[0049] Surfactant-producing microorganisms are those capable of producing glycolipid or lipopeptide biosurfactants and can adapt to high-temperature, high-pressure, and high-salt environments. The main function of these surfactant-producing microorganisms in this invention is to reduce the surface tension of saline water by utilizing the biosurfactants produced through their metabolism, thereby promoting CO2 dissolution in the saline water and improving the safety and stability of the sequestration process. Therefore, any microorganism capable of surviving in geological reservoir environments and producing surfactants can achieve the objectives of this invention.

[0050] Among them, the high temperature, high pressure, and high salinity environment is an environment with a mineralization degree >1g / L, a pressure of 8~20MPa, and a temperature of 35~75℃.

[0051] The glycoester biosurfactants include at least one of rhamnolipid, trehalose ester, and sophorolipid; the lipopeptide biosurfactants include at least one of lipopeptide, surfactant, myxobin, and polymyxin.

[0052] The present invention will be further illustrated by the following examples.

[0053] The following examples used Rha-T, Rha-S, and rhamnolipin standards to simulate laboratory conditions and improve CO2 geological sequestration capabilities. Rha-T was purchased from a microbial bank; Rha-S was a surfactant-producing strain screened by the applicant that maintained high activity under high temperature, high pressure, and high salt conditions; and the rhamnolipin standards were purified products obtained by the applicant from the extraction of rhamnolipin surfactants produced by microorganisms.

[0054] In the following embodiments, the method for detecting the concentration of dissolved CO2 in the system is as follows: Figure 2 As shown, the experimental procedure is as follows: Open the sampling port and pass a certain amount of liquid into gas collecting bottle No. 1 until the phenolphthalein fades. Close the sampling port and observe whether gas collecting bottles No. 2 to No. 6 become turbid. If all become turbid, add more gas collecting bottles and resample. After sampling, titrate gas collecting bottle No. 1 with NaOH standard solution until the solution turns pink and does not fade within half a minute, which is the endpoint. Filter, dry, and weigh gas collecting bottles No. 2 to No. 6, and calculate the mass of CO2 released.

[0055] Example 1: Rha-T resuscitation, culture and effects

[0056] S1: Prepare 50 mL and 200 mL of Luria-Bertani medium (pH = 7.0) in Erlenmeyer flasks, respectively, and sterilize at 121 °C for 20 min. Inoculate frozen Rha-T into 50 mL of medium and incubate on a shaker at 37 °C and 170 rpm until OD (October Expiratory Time). 600 >0.8, take 4 mL of the revived bacterial culture and inoculate it into 200 mL of sterilized Luria-Bertani medium. Continue to incubate at 37℃ and 170 r / min for 48 h. Measure and record OD every 12 h. 600 Value, when OD 600 After the value stabilizes, the OD of the bacterial culture... 600 =1.36, and the number of viable bacteria in the bacterial culture determined by flow cytometry was 7.4 × 10⁻⁶. 8 cells / mL.

[0057] S2: Add 500 mL of simulated saline water to 200 mL of LRha-T bacterial culture and mix well, then transfer it to an autoclave.

[0058] S3: Set the experimental temperature to 50℃ and the pressure to 10MPa, and begin the experiment. After the temperature reaches 50℃, turn on the pressurization system and inject CO2 gas into the reactor at a concentration of 99%, raising the system pressure to 10MPa. Start timing. Samples were taken at 12h, 5d, 10d, 15d, 20d, 25d, and 30d of the reaction to test relevant parameters. The results are shown in […]. Figure 3 , Figure 4 .

[0059] Example 2: Rha-S resuscitation, culture and effects

[0060] S1: Prepare 50 mL and 200 mL of Luria-Bertani medium (pH = 7.0) in Erlenmeyer flasks, respectively, and sterilize at 121 °C for 20 min. Inoculate Rha-S into 50 mL of the medium and incubate on a shaker at 37 °C and 170 rpm until OD (October Expiratory Time). 600 >0.8, take 4 mL of the revived bacterial culture and inoculate it into 200 mL of sterilized Luria-Bertani medium. Continue to incubate at 37℃ and 170 r / min for 48 h. Measure and record OD every 12 h. 600 Value, when OD 600 After the value stabilizes, the OD of the bacterial culture... 600 =1.33, and the number of microorganisms in the bacterial culture determined by flow cytometry was 8.1 × 10⁻⁶. 8 CFU / mL.

[0061] S2: Add 500 mL of simulated saline water to 200 mL of LRha-S bacterial culture and mix well, then transfer it to an autoclave.

[0062] S3: Set the experimental temperature to 50℃ and the pressure to 10MPa, and begin the experiment. After the temperature rises to 50℃, turn on the pressurization system and inject CO2 gas into the reactor at a concentration of 99%, raising the system pressure to 10MPa, and start timing. Samples are taken at 12h, 5d, 10d, 15d, 20d, 25d, and 30d of the reaction to test relevant parameters. The results are shown in […]. Figure 3 , Figure 4 .

[0063] Example 3: Effect of rhamnolipid standard

[0064] S1: Add rhamnolipin standard to 700mL of simulated saline water and mix well, then transfer it to an autoclave.

[0065] S2: Set the experimental temperature to 50℃ and the pressure to 10MPa, and begin the experiment. After the temperature rises to 50℃, turn on the pressurization system and inject CO2 gas into the reactor at a concentration of 99%, raising the system pressure to 10MPa, and start timing. Samples are taken at 12h, 5d, 10d, 15d, 20d, 25d, and 30d of the reaction to test relevant parameters. The results are shown in [the table below]. Figure 3 , Figure 4 .

[0066] Comparative Example 1: Control Group

[0067] S1: Take 700ml of the prepared simulated saline water and transfer it to the autoclave.

[0068] S2: Set the experimental temperature to 50℃ and the pressure to 10MPa, and begin the experiment. After the temperature rises to 50℃, turn on the pressurization system and inject CO2 gas into the reactor at a concentration of 99%, raising the system pressure to 10MPa, and start timing. Samples are taken at 12h, 5d, 10d, 15d, 20d, 25d, and 30d of the reaction to test relevant parameters. The results are shown in [the table below]. Figure 3 , Figure 4 .

[0069] The above description is only a preferred embodiment of the present invention. It should be noted that for those skilled in the art, several improvements and modifications can be made without departing from the principle of the present invention, and these improvements and modifications should also be considered within the scope of protection of the present invention.

Claims

1. A biological method for enhancing CO2 geological sequestration, characterized in that: Includes the following steps: CO2 and surfactant-producing microorganisms are injected into the geological reservoir through injection wells connected to surface facilities and the geological reservoir. The geological reservoir used for CO2 sequestration is a geological space containing formation water, including at least one of saline aquifers, depleted or abandoned oil and gas reservoirs. The surfactant-producing microorganisms metabolize to produce biosurfactants; The biosurfactant is used to reduce the surface tension of formation water, promote the dissolution of CO2 in formation water, and encapsulate the injected CO2 in a dissolved form. The surfactant-producing microorganisms are microorganisms capable of producing glycolipid or lipopeptide biosurfactants, and are adaptable to high temperature, high pressure, and high salt environments; the high temperature, high pressure, and high salt environment is an environment with a mineralization degree >1 g / L, a pressure of 8~20 MPa, and a temperature of 35~75℃; the glycolipid biosurfactants include at least one of rhamnolipid, trehalose, and sophorolipolipid; the lipopeptide biosurfactants include at least one of lipopeptides, surfactants, myxobin, and polymyxin.

2. A simulation test method for verifying the biological method for enhancing CO2 geological sequestration as described in claim 1, characterized in that: Includes the following steps: S1, the surfactant-producing strain was inoculated into sterilized Luria-Bertani medium and revived in a shaker at 37°C and 170 r / min; then, 2% of the revived bacterial solution was inoculated into sterilized Luria-Bertani medium and cultured in a shaker at 37°C and 170 r / min for 48 h to obtain the bacterial solution; the OD of the obtained bacterial solution was... 600 >0.8, number of microorganisms in bacterial solution >10 8 cells / ml; S2, mix the bacterial solution and the saline solution evenly, and place them in an autoclave; S3, CO2 is injected to raise the pressure inside the autoclave to the preset pressure, simulating the temperature, pressure, and types and concentrations of ions in the saline water layer. The evolution of dissolved CO2 concentration in the saline water over time is used to characterize the amount of dissolved CO2 in the saline solution, and the carbon content is compared with that under conditions with and without surfactant-producing strains. The conditions inside the autoclave are: temperature: 35~75℃; pressure: 8~20 MPa; time: 5~30 d; CO2 concentration >90%.

3. The simulation test method according to claim 2, characterized in that: In step S2, the saline solution is saline water taken from a saline layer at a depth of 800~2000 m, and its mineralization is >1 g / L.

4. The simulation test method according to claim 2, characterized in that: In step S2, the volume ratio of bacterial solution to saline solution is 0.1 to 1.

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