A formation pretreatment method for enhancing CO2 geological storage

Abstract

The present invention relates to a formation pretreatment method for enhancing the geological storage capacity of CO2, comprising: (1) injecting a certain amount of fresh water into a target saline water layer through an injection well to reduce the saline water layer salinity; (2) injecting a polyelectrolyte as a sacrificial agent into the target saline water layer through the injection well; (3) injecting a non-ionic surfactant solution into the target saline water layer through the injection well, using a low concentration followed by a high concentration slug injection; (4) continuously sampling the produced fluid of the reservoir to confirm that the concentration distribution of the surfactant solution in the reservoir meets the requirements; (5) injecting the CO2 to be stored into the saline water layer, ensuring that the CO2 is completely dissolved before carrying out the next CO2 slug injection; (6) repeating step (5) until no significant drop in bottom hole pressure is observed after the well is blocked and the pressure surges during injection, indicating that the formation water has reached a saturated state for dissolving CO2. The present invention effectively increases the storage capacity of CO2 in the saline water layer by pretreating the saline water layer, and has broad market application prospects.

Description

Technical Field

[0001] The present invention belongs to the technical field of CO2 geological storage, and in particular relates to a formation pretreatment method for CO2 chemical storage. Background Art

[0002] CO2 geological storage technology involves separating industrially generated CO2 and injecting it through drilling into deep underground saline aquifers, abandoned oil and gas reservoirs, or unmined coal seams, thereby achieving geological storage of CO2. Among various geological structures for CO2 storage, saline aquifers are the most widespread and offer the greatest storage potential. The geological storage mechanisms for CO2 in deep saline aquifers can generally be divided into two categories: physical and chemical. Physical storage primarily includes tectonic sequestration, bound gas sequestration, and hydrodynamic sequestration; research on physical CO2 storage has been extensive. Chemical storage primarily includes mineralization and dissolution. CO2 mineralization storage utilizes saline aquifers, which are typically composed of sandstone or limestone, containing minerals such as calcium, magnesium, potassium, and iron. CO2 reacts chemically with these minerals to form chemically stable carbonates, thereby achieving CO2 storage. However, this storage method has a long cycle time and low efficiency. CO2 dissolution and storage will occur throughout the storage cycle. When CO2 is injected into underground saline aquifers, due to the solubility of CO2, some CO2 will dissolve in the saline water to form CO2-rich saline water. The density of CO2-rich saline water is greater than that of the surrounding saline water. The density difference between the two will cause convective mixing, which will further increase the dissolution rate of CO2. At the same time, the saline water with dissolved CO2 will spontaneously sink to the bottom of the saline aquifer due to its high density, increasing the safety of storage. Dissolution storage is currently an effective means of achieving CO2 storage, but the solubility of CO2 in most saline aquifers is low, making the utilization efficiency of saline aquifer resources low. How to improve the solubility of CO2 in saline aquifers, achieve efficient utilization of saline aquifer resources, and further increase the storage capacity of CO2 deserves in-depth study.

[0003] Some scholars have studied the effects of pressure, temperature, and salinity on CO2 solubility (Yu Lisong, Zhang Weidong, Wu Shuangliang, et al. Research Progress on the Dissolution and Storage of Carbon Dioxide in Deep Saline Aquifers [J]. New Energy Progress, 2015(1):6), but have not addressed how to increase CO2 solubility in saline aquifers. The invention patent "A Method for Capturing and Separating CO2 from a Gas Mixture" (CN104275083B) increases CO2 solubility by adding an organic solvent to methanol. While this method increases CO2 solubility, it requires a long workflow and large equipment investment.

[0004] Since CO2 has a low solubility in most saline aquifers, its storage efficiency is low, resulting in a large waste of saline aquifer resources. Existing research and methods have failed to effectively increase the solubility of CO2 in saline aquifers.

[0005] To solve this problem, the present invention proposes a formation pretreatment method for CO2 chemical storage, and the applicable formation temperature should be less than 65°C. Summary of the Invention

[0006] The present invention aims to provide a formation pretreatment method for enhancing CO2 geological storage. This method, with reliable principles and simple operation, increases the solubility of CO2 in saline aquifers by pretreating them, enabling rapid dissolution and effectively increasing CO2 storage capacity. Compared to untreated saline aquifers, the solubility of CO2 in pretreated saline aquifers can be increased by more than four times, demonstrating broad market application prospects.

[0007] In order to achieve the above technical objectives, the present invention adopts the following technical solutions.

[0008] A formation pretreatment method for enhancing CO2 geological storage capacity comprises the following steps:

[0009] (1) When the reservoir salinity is high (>50,000 mg / L), taking the optimal storage capacity as the target, a certain amount of fresh water is injected into the target saline layer through the injection well to reduce the salinity of the saline layer and increase the reservoir pressure to a certain extent, which can improve the applicability of surfactants and CO2 solubility;

[0010] (2) A polyelectrolyte with a mass concentration of 0.5% and a slug size of 0.1 PV (PV is pore volume) is injected into the target saline layer through an injection well as a sacrificial agent to prevent the surfactant from being adsorbed in large quantities on the rock wall of the formation, which would weaken the effect;

[0011] (3) Inject a non-ionic surfactant solution into the target saline layer through an injection well. The mass concentration of the surfactant solution is 0.1-5%, the slug size is 0.1-0.2PV, and the injection volume is less than 0.6PV. According to the specific physical properties of the reservoir, a low-concentration slug injection is adopted first and then a high-concentration slug injection is adopted;

[0012] (4) Continuously sampling the produced fluid from the reservoir, analyzing the concentration changes of the sacrificial agent and the surfactant in the produced fluid, adjusting the concentration and dosage of the sacrificial agent and repeating steps (2) to (4) until it is confirmed that the concentration distribution of the surfactant solution in the reservoir meets the requirements;

[0013] (5) Inject the CO2 to be buried into the saline layer at a rate of 0.1PV. After one CO2 plug is injected, seal the well and monitor the bottom hole pressure until it drops to the pressure before CO2 injection. Ensure that the CO2 is completely dissolved before injecting the next CO2 plug.

[0014] (6) Repeat step (5) until no significant drop in bottomhole pressure is observed after the well is sealed and the pressure surges during injection, indicating that the formation water has reached saturation for CO2 dissolution.

[0015] Furthermore, in step (1), when the reservoir salinity is low or cost requirements are taken as the target, the formation water may not be diluted.

[0016] Furthermore, in step (2), the polyelectrolyte is polystyrene sulfonic acid (PSS) or polyacrylate (PA).

[0017] Furthermore, in the step (3), the nonionic surfactant is polyethylene glycol 4-tert-octylphenyl ether TX-45 (C 14 H 22 O(C2H4O)n, n=5), polyethylene glycol octylphenyl ether TX-100 (C 14 H 22 O(C2H4O)n, n=10) or polyoxyethylene mono-tert-octylphenyl ether TX-114 (C 14 H 22 O(C2H4O)n, n=7.5).

[0018] Furthermore, in step (4), the produced fluid of the reservoir is continuously sampled, and the concentration changes of the sacrificial agent and the surfactant in the produced fluid are analyzed by high performance liquid chromatography. The adsorption of the surfactant is determined by the migration of the sacrificial agent. If the surfactant concentration in the produced fluid is low or the sacrificial agent concentration is high, the sacrificial agent selection and concentration should be adjusted and steps (2) to (4) should be repeated.

[0019] Furthermore, in step (5), if the injection well has a large controlled area, CO2 gas slugs and surfactant solution slugs are injected alternately.

[0020] The nonionic surfactant in this invention has high surface activity, good salt resistance and stability, and a cloud point of approximately 64°C. Therefore, it can quickly dissolve in formation water in the formation environment, thereby achieving formation pretreatment. During the injection process, it improves the dissolution and mass transfer efficiency, monitors the formation pressure, and determines the dissolution status.

[0021] Compared with the prior art, the present invention has the following beneficial effects:

[0022] (1) The chemicals used are cheap, and the cost of increasing CO2 storage capacity is low;

[0023] (2) The surfactant used increases the solubility of CO2 in the saline water layer, greatly increasing the storage capacity of CO2 in the saline water layer. BRIEF DESCRIPTION OF THE DRAWINGS

[0024] Figure 1 This is the solubility curve of CO2 in salt water.

[0025] Figure 2 This is the solubility curve of the mixed system after adding surfactant to brine. DETAILED DESCRIPTION

[0026] The present invention is further described below with reference to the accompanying drawings and examples to facilitate understanding by those skilled in the art. However, it should be understood that the present invention is not limited to the specific embodiments described herein. It will be apparent to those skilled in the art that any variations within the spirit and scope of the present invention as defined and established by the appended claims are intended to be protected. Example

[0027] A formation pretreatment method for enhancing CO2 geological storage capacity, comprising the following steps:

[0028] (1) Prepare 1L of brine with a mineral content of 5g / L;

[0029] (2) Place the prepared brine into the lower end of the sample preparation device and introduce excess CO2 into the upper end to ensure that the CO2 can be completely dissolved in the brine;

[0030] (3) Set the sample dispenser temperature to 25°C and the pressure to 15 bar, start the sample dispenser, and after stirring for 48 hours, use the drainage gas collection method to measure the gas volume to be 800 mL (1.6 g), and the brine volume to be 120 mL (100 g), with a solubility of 1.6 g / 100 g.

[0031] (4) Prepare saline solution with the same conditions and add 0.25 mL of 1% surfactant TX-100 to it, repeat steps (1) to (3), and measure its solubility to be 5.8 g / 100 g;

[0032] (5) The solubility of CO2 in brine with or without surfactant TX-100 was tested at different temperatures and pressures. The experimental results showed that the solubility of CO2 in the solution mixed with surfactant was much higher than that in the single brine (see the test results). Figure 1 、 Figure 2 ).

Claims

1. A formation pretreatment method for enhancing CO2 geological storage capacity, comprising the following steps: (1) When the reservoir mineralization is high, a certain amount of fresh water is injected into the target saline layer through the injection well to reduce the salinity of the saline layer; (2) injecting a polyelectrolyte with a mass concentration of 0.5% and a slug size of 0.1 PV into the target saline layer through an injection well as a sacrificial agent to prevent the large-scale adsorption of the surfactant on the rock wall of the formation; the polyelectrolyte is polystyrene sulfonic acid or polyacrylate; (3) injecting a nonionic surfactant solution into the target saline layer through an injection well, wherein the mass concentration of the surfactant solution is 0.1-5%, the slug size is 0.1-0.2PV, the injection volume is less than 0.6PV, and the slug injection is performed first with low concentration and then with high concentration. The nonionic surfactant is polyethylene glycol 4-tert-octylphenyl ether, polyethylene glycol octylphenyl ether or polyoxyethylene mono-tert-octylphenyl ether; (4) Continuously sampling the produced fluid from the reservoir, analyzing the concentration changes of the sacrificial agent and the surfactant in the produced fluid, adjusting the concentration and dosage of the sacrificial agent and repeating steps (2) to (4) until the concentration distribution of the surfactant solution in the reservoir meets the requirements; (5) Inject the CO2 to be buried into the saline layer at a rate of 0.1PV. After one CO2 plug is injected, seal the well and monitor the bottom hole pressure until it drops to the pressure before CO2 injection. Ensure that the CO2 is completely dissolved before injecting the next CO2 plug. (6) Repeat step (5) until no significant drop in bottomhole pressure is observed after the well is sealed and the pressure surges during injection, indicating that the formation water has reached saturation for CO2 dissolution.

2. A formation pretreatment method for enhancing CO2 geological storage according to claim 1, characterized in that: In the step (1), when the reservoir salinity is low or cost requirements are taken as the target, the formation water may not be diluted.

3. The formation pretreatment method for enhancing CO2 geological storage according to claim 1, characterized in that: In step (4), the produced fluid of the reservoir is continuously sampled, and the concentration changes of the sacrificial agent and the surfactant in the produced fluid are analyzed. The adsorption of the surfactant is determined by the migration of the sacrificial agent. If the surfactant concentration in the produced fluid is low or the sacrificial agent concentration is high, the sacrificial agent selection and concentration are adjusted and steps (2) to (4) are repeated.

4. The formation pretreatment method for enhancing CO2 geological storage according to claim 1, characterized in that: In step (5), if the injection well has a large controlled area, CO2 gas slugs and surfactant solution slugs are injected alternately.

Images