Characterization method of change of carbon dioxide salt water layer sealing pore permeability along with time based on carbon dioxide-water-rock reaction

Abstract

The invention discloses a method for characterizing changes of carbon dioxide salt water layer sealing pore permeability along with time based on a carbon dioxide-water-rock reaction. The method for characterizing the change of the carbon dioxide salt water layer sealing pore permeability along with the time based on the carbon dioxide-water-rock reaction comprises the following steps: carrying out a static CO2-water-rock reaction simulation experiment on a saturated core by adopting experimental formation water to obtain the particle sizes of suspended matters under different pressures; performing dynamic CO2-water-rock reaction experiments in the injection process under different pressures by adopting different research area stratum cores, and performing mercury injection test, porosity test and permeability test on the research area stratum cores before and after the experiments to obtain porosity and permeability change rate charts after CO2-water-rock reaction under different pressures; the long-term CO2-water-rock reaction pore permeability change is simulated through multi-field coupling of the model, and the quantification of the change of the pore permeability along with the time in the whole sealing process of injecting the carbon dioxide into the salt water layer is obtained.

Description

Technical Field

[0001] The invention belongs to the technical field of carbon dioxide saline water layer sealing, and relates to a method for characterizing the change of porosity and permeability of carbon dioxide saline water layer sealing over time based on carbon dioxide-water-rock reaction. Background Art

[0002] CO 2 Saline aquifer storage is one of the important means of CCUS. Its storage capacity and injection rate are mainly determined by the porosity and permeability of the reservoir. Therefore, the reservoir properties during the injection phase and after the injection is stopped are the key factors in designing CO 2 Important parameters for saline aquifer storage options. 2 Reacts with formation water to generate carbonic acid, which ionizes to produce H + , HCO 3 - and CO 3 2- These ions can react with minerals in rocks, causing primary minerals such as calcite, dolomite, feldspar, and clay to dissolve, increasing the porosity and permeability of rocks. At the same time, the precipitation of secondary minerals and the migration of particles may block pores and reduce the permeability of rocks. Therefore, considering the CO 2 In the two stages of storage injection and post-injection, it is urgent to propose a method that takes into account CO 2 -CO from water-rock reaction 2 A quantitative characterization method for porosity and permeability of saline aquifers for guiding CO 2 Development of storage plan. Summary of the invention

[0003] The purpose of the present invention is to provide a method for characterizing the time-dependent changes in porosity and permeability of carbon dioxide stored in saline aquifers based on carbon dioxide-water-rock reaction.

[0004] The present invention provides a method for characterizing the change of porosity and permeability of carbon dioxide stored in saline water layers over time based on carbon dioxide-water-rock reaction, comprising the following steps:

[0005] 1) According to the actual formation water composition of the target saline layer reservoir produced in the target oil field, the experimental formation water is compounded to saturate the formation core of the study area; the saturated core is saturated with the experimental formation water through a static CO 2 - Water-rock reaction simulation experiment to determine CO 2 - The initial reaction type of water-rock reaction, the type of sediment, and the measured sediment particle size; then repeat the above steps at different pressures to simulate CO 2 The formation pressure around the injection well changes, and the particle size of the suspended matter under different pressures is obtained;

[0006] 2) Use formation cores from different study areas and conduct dynamic CO injection process experiments under the different pressures described in step 1) 2 -water-rock reaction experiments, and before and after the experiments, conduct mercury intrusion tests, porosity tests, and permeability tests on the formation cores of the study areas respectively;

[0007] Based on the results of the mercury intrusion tests, calculate the cumulative permeability contribution of each formation core in the study areas that is less than the pore throat radius, and draw a permeability contribution chart according to the results; among them, the pore throat radius is less than the suspended solid particle size determined in step 1);

[0008] According to the permeability test results, calculate the cumulative permeability contribution of each group of experimental samples, draw a curve of the permeability contribution and permeability relationship of each sample, and fit to obtain the effective porosity calculation formula of the saline aquifer considering CO 2 -water-salt reaction precipitation, and determine the effective permeability at this pressure;

[0009] Combined with the porosity test results, draw a chart of the porosity and permeability change rates after CO 2 -water-rock reaction at different pressures;

[0010] 3) Based on the reservoir physical properties, temperature and pressure conditions, and formation water composition of the target saline aquifer, through the TOUGH numerical simulation method, establish a single-well CO injection model for the saline aquifer based on the chemical reactions confirmed in step 1) 2 Model, fit through the chart of the porosity and permeability change rates after CO 2 -water-rock reaction at different pressures obtained in step 2), and obtain a multi-field coupling model of CO 2 -water-rock reaction in the target saline aquifer; use the porosity-time and permeability-time relationships at different pressures in step 2) to correct the multi-field coupling model chart of CO 2 -water-rock reaction in the target saline aquifer to obtain a prediction chart of the change of porosity and permeability with time; then conduct numerical simulation of the single-well CO injection model in the saline aquifer described above 2 -water-rock reaction to obtain the quantitative change of pore permeability with time in the whole process of carbon dioxide injection and storage in the saline aquifer. 2 In the above method, the steps of the static CO 2 -water-rock reaction simulation experiment in step 1) are as follows: Use the formation water for the experiment on the saturated core, inject CO in the reaction kettle at the formation temperature and pressure

[0011] and react for 16 days; filter the reacted formation water in the sampling device through a mixed cellulose filter membrane with a pore size of 0.45 μm, and conduct SEM-EDS analysis on the filtered solid particles to determine CO 2 ; 2 and react for 16 days; filter the reacted formation water in the sampling device through a mixed cellulose filter membrane with a pore size of 0.45 μm, and conduct SEM-EDS analysis on the filtered solid particles to determine CO 2- The solid-phase composition of the precipitate formed by the water-rock reaction was measured, and the particle size of the precipitate was determined. The formation water after partial reaction in the sampler was analyzed by ICP-AES to determine the CO 2 The change in the cation concentration of the solution after reacting with the formation water was determined to identify the dissolution and precipitation reactions during the reaction process.

[0012] In the above method, in step 1), the different pressures are 30 to 60 MPa, specifically 30, 40, 50, and 60 MPa. Specifically, according to the formation pressure of different saline aquifers, the experimental pressure is adjusted to match the formation pressure rise after injecting CO 2

[0013] In the above method, in step 2), the permeability contribution at a certain pore throat radius is calculated according to the following formula (1), and the cumulative permeability contribution is calculated according to the following formula (2):

[0014]

[0015] ΔK i — Permeability contribution

[0016] r i — Pore throat radius, μm

[0017] α i — Ingress saturation, %

[0018] Cumulative permeability contribution:

[0019]

[0020] A k — Cumulative permeability contribution, %.

[0021] The principle of the method of the present invention is as follows:

[0022] CO 2 After being injected into the formation, it undergoes a series of dissolution and precipitation reactions with the minerals in the rock, and the reaction rates of each reaction are controlled by temperature and pressure. During the injection process of sequestration, the pressure around the wellbore gradually rises, and the CO 2 - The type and degree of water-rock reaction change with the change of pressure. Therefore, the CO 2 during the injection stage can be simulated by conducting static experiments on natural cores at different pressures in the laboratory, and by testing the composition of the formation water after the reaction, the reaction type and the size of the precipitate particles can be determined. Through CO 2 - water-rock reaction, 2 ​- Water-rock reaction dynamic experiment, combined with mercury intrusion experiment, to determine the effective permeability after precipitation particle plugging, and obtain the relationship between porosity and permeability changes under different pressures. Through the above experiments, the reaction type and the relationship between pore permeability and pressure can be used to establish a TOUGH numerical model and perform fitting correction, and then can be used to simulate the CO 2 The relationship between pore permeability changes during the whole process after CO injection and shut-off, and complete the quantitative evaluation of reservoir damage during the whole process of CO 2 injection in complex offshore oilfields.

[0023] The present invention has the following beneficial effects:

[0024] Through the dynamic and static experiments of the interaction between CO 2 and formation fluids and rocks and TOUGH numerical simulation, the types of dissolution reaction and precipitation reaction that occur between CO 2 and water-rock after injecting into the target saline aquifer are determined, the solid phase composition of the precipitated solids and the precipitation particle size are determined, and the relationship between porosity and permeability change rates of CO 2 -water-rock reaction under different pressures is formed. 2 The porosity and permeability change rate chart after CO -water-rock reaction is established, and a TOUGH multi-field coupling numerical model is built. Finally, a prediction chart of pore diameter, porosity and permeability changing with time is formed.

[0025] Figure 1 is the analysis of the particle size of suspended solids in bottom water under different CO 2 injection pressures.

[0026] Figure 2 is the porosity and permeability change rate chart after CO 2 -water-rock reaction under different pressures.

[0027] Figure 3 is the schematic diagram of the TOUGH model.

[0028] Figure 4 is the prediction chart of porosity and permeability changing with time.

[0029] Figure 5 is the prediction chart of pore diameter-injection time. Detailed implementation manners

[0030] The experimental methods used in the following examples are all conventional methods unless otherwise specified.

[0031] The materials, reagents, etc. used in the following examples can be obtained from commercial channels unless otherwise specified.

[0032] CO 2After being injected into the formation, a series of dissolution reactions and precipitation reactions occur with the minerals in the rock, and the reaction rates of each reaction are controlled by temperature and pressure. During the injection and storage process, the pressure around the wellbore gradually rises, and the type and degree of CO 2 -water-rock reactions change with the change of pressure. Therefore, static experiments can be carried out on natural cores at different pressures in the laboratory to simulate the CO 2 -water-rock reactions during the injection stage of CO 2 By testing the composition of the formation water after the reaction, the reaction type and the size of the precipitation particles can be determined. Through the dynamic experiment of CO2-water-rock reaction and combined with the mercury injection experiment, the effective permeability after the precipitation particles are blocked can be determined, and the relationship between porosity and permeability changes at different pressures can be obtained. The relationship between the reaction type, porosity and permeability changing with pressure obtained through the above experiments can be used to establish a TOUGH numerical model and perform fitting and correction, and then can be used to simulate the relationship between porosity and permeability changes in the whole process after CO 2 injection and after injection stopping, and complete the quantitative evaluation of reservoir damage in the whole process of CO 2 injection in offshore complex oilfields.

[0033] Example

[0034] 1. Static CO 2 -water-rock reaction simulation experiment

[0035] Through the water-rock reaction simulation experiment, determine the initial reaction type, precipitate type of CO 2 -water-rock reaction, and measure the particle size of the precipitate.

[0036] (1) Analyze according to the composition of the formation water actually produced at the target oilfield site, compound the formation water for the experiment, and measure the ion concentration under the initial conditions;

[0037] (2) Inject 600 mL of the compounded formation water into a high-temperature and high-pressure reactor, and then seal the top cover of the reactor. Heat the reactor to the experimental temperature, and adjust the CO 2 boost injection system to inject CO 2 into the reactor. At the same time, start the electromagnetic stirrer in the reactor to dynamically stir the fluid in the reactor. After the pressure in the reactor reaches the experimental pressure, close the CO 2 injection system and carry out the CO 2 -formation water reaction for 16 days;

[0038] (3) After the reaction is completed, sample the formation water after the reaction at the sampling valve at the lower part of the reactor, and further analyze the ion concentration, precipitation amount and precipitation composition of the sampled formation water;

[0039] (4) Filter the reacted formation water in the sampler through a CN-CA filter membrane (mixed cellulose filter membrane) with a pore size of 0.45 μm, and perform SEM-EDS analysis on the filtered solid particles to determine the solid-phase composition of the precipitate formed by the CO 2 -water-rock reaction, and measure the particle size of the precipitate as R;

[0040] (5) Perform ICP-AES analysis on part of the reacted formation water in the sampler to determine the change in the cation concentration of the solution after the CO 2 -water-rock reaction, and determine the dissolution and precipitation reactions during the reaction;

[0041] (6) Repeat the above steps at 30, 40, 50, and 60 MPa.

[0042] Specifically, carry out the CO 2 -water-rock reaction simulation experiment on Oilfield A (whose basic physical and chemical characterization parameters are shown in Table 1), and the reaction equation occurring in the solution is obtained as follows:

[0043] 1) CO 2 Dissolves in formation water:

[0044] CO 2 + H 2 O → H 2 CO 3 (3-1)

[0045] H 2 CO 3 → H+ + HCO 3 - (3-2)

[0046] HCO 3 - → H+ + CO 3 2- (3-3)

[0047] Table 1

[0048]

[0049] 2) CO 2 After being injected into the formation water, dissolution and precipitation occur:

[0050] Ca 2 + + CO 3 2- → CaCO 3 (s) (calcite) (3-4)

[0051] Mg 2+ / Fe 2++ CO 3 2- → (Mg / Fe)CO 3 (s)(Siderite / magnesite) (3-5)

[0052] Ca 2+ + Mg 2+ + 2 CO 3 2- → CaMg (s)(Dolomite) (3-6)

[0053] 3)CO 2 Dissolution of minerals after injection into the formation:

[0054] CaCO 3 (s)(Calcite)+H+→Ca 2+ +HCO 3- (3-7)

[0055] 2NaAlSi 3 O 8 (Albite)+CO 2 +11H 2 CO 3 →2Na 2+ +2HCO 3 - +4H 4 SiO 4 +Al 2 Si 2 (OH) 4 (Kaolinite)(3-8)

[0056] The particle sizes of suspended solids at different pressures are as follows: As Figure 1 shown, the peak particle size of solid-phase particles of suspended solids in the original formation water is mainly 513.2 nm. As the pressure increases, the peak of particle size in the solution gradually shifts to the right, and the particle size of solid-phase particles in the solution becomes larger. When the pressure reaches 40 MPa, the peak particle size of solid-phase particles in the solution reaches 1718 nm. When the pressure is higher than 50 MPa, the particle size of suspended solids in the formation water becomes smaller, and the peak returns to about 815 nm.

[0057] 2. Dynamic characterization method for pore permeability change during injection process

[0058] 2.1 Dynamic experiment

[0059] Using the formation core of the study area (the same core as the one in the aforementioned static water-rock reaction), water-rock reaction is carried out. The reaction temperature is the initial formation temperature of 150 °C. Four cores correspond to reaction pressures of 30, 40, 50, and 60 MPa respectively, corresponding to the pressure change around the well during the injection process. Before and after the experiment, mercury intrusion tests, porosity and permeability tests are carried out on the cores respectively.

[0060] (1) Place the core in an oven for drying treatment for 48 hours. Measure the dry weight and dimensions;

[0061] (2) Subject the core to vacuum pumping and pressure saturation, measure the wet weight, and the saturated fluid is formation water;

[0062] (3) Place the core in a reactor that has been pre-poured with formation water, close the top cover of the reactor and seal it. Conduct vacuum treatment on the reactor to remove the air at the bottom of the formation water, and then inject CO 2 gas to the initial formation pressure. Control the temperature and pressure of the reactor, and the experimental time is 16 days;

[0063] (4) After the experiment, measure the wet weight. Then, place the core in an oven for drying treatment for 48 hours and measure the dry weight.

[0064] (5) Conduct mercury injection experiments, porosity, and permeability tests on the core after the CO 2 -water-rock reaction.

[0065] (6) Adjust the reactor pressure and repeat steps (1)-(5).

[0066] 2.2 Calculation of effective permeability considering reaction precipitation plugging

[0067] (1) Based on the results of high-pressure mercury injection experiments, calculate the cumulative permeability contribution of each rock sample at different pore throat radii according to Equations 1 and 2, and draw a permeability contribution chart based on the results. Where ri < R (the suspended solid particle size determined in step 1). Calculate the cumulative permeability contribution of each group of experimental samples, draw the curve of permeability contribution and permeability relationship of each sample, and the fitted curve expression is the formula for calculating the effective porosity of this saline aquifer considering CO 2 -water-salt reaction precipitation.

[0068] Permeability contribution at a certain pore throat radius:

[0069]

[0070] ΔK i —Permeability contribution

[0071] r i —Pore throat radius, μm

[0072] α i —Contribution saturation, %

[0073] Cumulative permeability contribution:

[0074]

[0075] Ak — Cumulative permeability contribution, %

[0076] (2) Combining with the porosity experiment, the effective permeability and porosity change rate charts at different reaction pressures are obtained (as Figure 2 ).

[0077] As analyzed from Figure 2 , the water-rock reaction causes mineral dissolution, so the porosity increases. The degree of porosity increase increases with the increase of reaction pressure.

[0078] 3. Multi-field coupling simulation of long-term CO 2 -water-rock reaction pore and permeability changes

[0079] (1) Based on the physical properties, temperature and pressure conditions of the target saline aquifer reservoir, and the reaction equations obtained from the static CO 2 -water-rock reaction simulation experiment in step 1, a single-well CO injection model for the saline aquifer is constructed by TOUGH software as 2 shown in Figure 3 .

[0080] (2) Using the matching relationship between the injection stage pressure and pore and permeability relationship obtained in the dynamic characterization method of reservoir pore and permeability changes in step 2 to fit and correct the multi-field coupling simulation, a multi-field coupling model for CO 2 -water-rock reaction in the target saline aquifer is obtained 2 .

[0081] (3) Through numerical simulation, the curves of the changes of porosity, permeability and pressure with injection time are obtained. Using the porosity-time and permeability-time relationships at different pressures in step 2 (that is, the porosity-pressure relationship is obtained in 2.1, and the permeability-pressure relationship is obtained in 2.2; the model can obtain the porosity-pressure-time relationship and the permeability-pressure-time relationship, and through conversion, the porosity-time relationship and the permeability-time relationship are obtained) to correct the chart, and the predicted charts of porosity and permeability changes with time are obtained (as Figure 4 shown).

[0082] According to Figure 4 the multi-field coupling simulation results of CO 2 flooding in Oilfield A shown, the reservoir permeability increases by 0.2% after 10 years, and long-term injection and storage of CO 2 is beneficial to the improvement of reservoir physical properties.

[0083] (4) Through numerical simulation, the curve of the change of pore diameter with injection time is obtained, and the predicted chart of pore diameter-injection time is drawn (as Figure 5 shown).

[0084] According to Figure 5The shown pore diameter change. In Oilfield A, the pore diameter increases continuously with the CO 2 injection, increasing from 0.25 μm to 3.20 μm.

[0085] Applying this method to Oilfield A, according to the multi-field coupling simulation results of CO 2 flooding in Oilfield A, the reservoir permeability increases by 0.2% after 10 years. The carbonates (calcite and dolomite) in the reservoir dissolve, confirming that CO 2 long-term injection and sequestration are beneficial to the improvement of reservoir physical properties. The permeability damage rate of the core after CO 2 flooding is 0.89% - 0.97%.

Claims

1. A method for characterizing the time-dependent changes in porosity and permeability of carbon dioxide stored in saline aquifers based on carbon dioxide-water-rock reaction, comprising the following steps: 1) Analyze the formation water composition of the target saline layer reservoir actually produced at the target oil field, compound the experimental formation water, and saturate the formation core of the study area; use the experimental formation water to conduct a static CO2-water-rock reaction simulation experiment on the saturated core to determine the initial reaction type and precipitation type of the CO2-water-rock reaction, and measure the precipitation particle size; then repeat the above steps under different pressures to simulate the formation pressure changes around the CO2 injection well, and obtain the suspended matter particle size under different pressures; 2) using cores from different study areas, respectively, to conduct a dynamic CO2-water-rock reaction experiment during the injection process at the different pressures described in step 1), and to conduct a mercury injection test, a porosity test, and a permeability test on the cores from the study areas before and after the experiment; Based on the results of the mercury injection test, the cumulative permeability contribution of the core of each formation in the study area that is smaller than the pore throat radius is calculated, and a permeability contribution chart is drawn according to the results; wherein, The pore throat radius is smaller than the suspended matter particle size determined in step 1); According to the permeability test results, the cumulative permeability contribution of each group of experimental samples is calculated, and the permeability contribution and permeability relationship curve of each sample is drawn, and the effective porosity calculation formula of the saline layer considering CO2-water-salt reaction precipitation is obtained by fitting, and the effective permeability under the pressure is determined; Then, in combination with the porosity test results, a graph of porosity and permeability change rates after CO2-water-rock reaction under different pressures is drawn; 3) Based on the physical properties, temperature and pressure conditions, and formation water composition of the target saline water layer reservoir, a single-well CO2 injection model for the saline water layer is established based on the chemical reaction confirmed in step 1) by the TOUGH numerical simulation method, and the porosity and permeability change rate charts after the CO2-water-rock reaction under different pressures obtained in step 2) are fitted to obtain a CO2 flooding multi-field coupling model for the target saline water layer considering the CO2-water-rock reaction; the porosity-time and permeability-time relationships under different pressures in step 2) are used to calibrate the CO2 flooding multi-field coupling model chart for the target saline water layer considering the CO2-water-rock reaction to obtain a porosity and permeability change prediction chart over time; then, a numerical simulation of the single-well CO2 injection model for the saline water layer is carried out to obtain a quantitative analysis of the porosity and permeability change over time for the entire process of CO2 injection into the saline water layer for storage.

2. The method according to claim 1, characterized in that: The steps of the static CO2-water-rock reaction simulation experiment in step 1) are as follows: the saturated core is treated with the experimental formation water, and CO2 is injected into the reactor at the formation temperature and pressure to react for 16 days; the reacted formation water in the sampler is filtered through a mixed cellulose filter membrane with a pore size of 0.45 μm, and the filtered solid particles are analyzed by SEM-EDS to determine the solid phase composition of the precipitate generated by the CO2-water-rock reaction and the particle size of the precipitate; the partially reacted formation water in the sampler is analyzed by ICP-AES to determine the change in the solution cation concentration after the reaction of CO2 and formation water, and to determine the dissolution and precipitation reactions during the reaction.

3. The method according to claim 1 or 2, characterized in that: In step 1), the range of the different pressures is 30 to MPa.

4. The method according to claim 1 or 2, characterized in that: In step 2), the permeability contribution at a certain pore throat radius is calculated according to the following formula (1), and the cumulative permeability contribution is calculated according to the following formula (2): ΔK i —Permeability contribution r i —Pore throat radius, μm α i — Tribute saturation, % Cumulative penetration contribution: A k —Cumulative penetration contribution, %.

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