Evaluation method for distinguishing rock physical property change caused by CO2 flooding extraction effect and corrosion effect

Abstract

According to the evaluation method for distinguishing the rock physical property change caused by the CO2 flooding extraction effect and the corrosion effect, the change of the rock physical property caused by the interaction of organic (asphaltene) precipitation and inorganic (CO2-formation water-rock) is analyzed and distinguished, and the evaluation accuracy is improved.

Description

Technical Field

[0001] The invention belongs to the technical field of oil and gas development experiments and relates to an evaluation method for distinguishing changes in rock properties caused by CO2 drive extraction and dissolution. Background Art

[0002] Gas injection has become the main development method for various oil fields. In the process of CO2 injection in tight light oil reservoirs, the extraction of light components often causes asphaltene deposition. The asphaltene molecules in the crude oil continue to flocculate and deposit, accumulating in the pores of the reservoir rock to block the pore throats, affecting the physical properties of the rock and making it difficult to extract tight oil and gas.

[0003] In existing research, CN114674699A discloses an experimental device for determining the characteristics of asphaltene precipitation in formation crude oil; CN113655202A discloses a method and system for testing the distribution pattern of asphaltene precipitation in CO2 flooding; CN107941838A discloses a quantitative evaluation method for the effect of asphaltene precipitation on pore throat distribution during CO2 flooding; CN112431576A discloses a method for evaluating the effect of asphaltene precipitation in CO2 flooding on recovery; Yu Zhichao et al., in the article "Water-Rock Interaction Experiment in Saturated CO2 Formation Water Flooding", studied the changes in reservoir lithology and physical properties after CO2 injection in Volume 33, Issue 6, 2012, Journal of Petroleum, 2017; Volume 38, Issue 3 In the 5th issue of Xinjiang Petroleum Geology, Wang Chen et al. studied the microscopic damage mechanism of asphaltene deposition caused by CO2 driving on reservoirs with different permeabilities in the article "Microscopic damage mechanism of asphaltene deposition caused by CO2 driving on cores"; in the 12th issue of Volume 42 of 2021, Acta Petrolei Sinica, Huang Xing et al. studied the asphaltene deposition characteristics and its damage mechanism to reservoirs under two injection methods, CO2 displacement and CO2 huff and puff, in the article "Asphaltene deposition and reservoir damage characteristics under different CO2 injection methods in tight light oil reservoirs"; in the 29th issue of Volume 2022, Special Oil and Gas Reservoirs, Sun Ting et al. took shale as the research object in the article "Analysis of asphaltene precipitation characteristics and influencing factors of CO2 driving in shale reservoirs", and studied the influence of reservoir parameters and injection parameters on CO2 displacement effect and asphaltene precipitation.

[0004] In existing research, the focus is mainly on the influence of water-rock interaction on reservoir physical properties (inorganic effect) during CO2 flooding, or the damage of asphaltene deposition to cores caused by CO2 flooding (organic precipitation). Although Wang Chen et al. explained the damage mechanism of asphaltene deposition to reservoirs caused by CO2 flooding at the microscopic pore throat structure level in the article "Microscopic Damage Mechanism of Asphaltene Deposition to Cores Caused by CO2 Flooding", they used artificial cores to exclude the influence of CO2-water-rock interaction on experimental results. It can be seen that there is no report on the influence and distinction of both (organic and inorganic effects) on reservoir physical properties during CO2 flooding. Summary of the invention

[0005] In view of the problems existing in the prior art, the present invention provides an evaluation method for distinguishing the changes in rock physical properties caused by CO2 extraction and dissolution. The evaluation method analyzes and distinguishes the changes in core physical properties caused by organic (asphaltene) precipitation and inorganic (CO2-formation water-rock) interactions, thereby improving the accuracy of the evaluation.

[0006] To achieve the above object, the present invention adopts the following technical solutions:

[0007] One of the purposes of the present invention is to provide an evaluation method for distinguishing changes in rock properties caused by CO2 flooding extraction and dissolution, the evaluation method comprising:

[0008] Using a core sample saturated with experimental simulated formation water that reaches the formation water salinity, measuring the permeability and porosity of the core sample;

[0009] Expelling simulated formation water from the core sample, heating the core sample to formation temperature, pressurizing the core sample to formation pressure, and saturating the core sample with experimental simulated oil until no water overflows;

[0010] Heating the core sample to the reservoir temperature, pressurizing the core sample to the reservoir pressure, and saturating the core sample with experimental simulated oil until no water overflows;

[0011] injecting CO2 into the core sample, and producing experimental simulated oil at bubble point pressure until no oil is produced;

[0012] The core sample is washed with n-heptane, and after displacing the fluid in the core sample, asphaltene precipitation in the pore throat is retained, and after drying, the permeability and porosity of the core sample affected by asphaltene precipitation and CO2-formation water-rock interaction are measured;

[0013] The asphaltene precipitates in the pore throats are removed, and after drying, the permeability and porosity of the core sample affected only by the CO2-formation water-rock interaction are measured.

[0014] As a preferred technical solution of the present invention, before using the experimental simulated formation water saturated core sample that reaches the formation water mineralization degree, the core sample is subjected to oil removal and drying treatment.

[0015] As a preferred technical solution of the present invention, the formation water mineralization is the formation water mineralization of the oil reservoir where the core sample is located.

[0016] As a preferred technical solution of the present invention, the calculation formula of the permeability is:

[0017]

[0018] Where: φ is porosity, %; V p is the pore volume, cm3; V b is the total volume of the core, cm 3 .

[0019] As a preferred technical solution of the present invention, the calculation formula of the porosity is:

[0020]

[0021] Where: Q0 is the volume flow rate under atmospheric pressure, cm / s; p1 and p2 are the inlet and outlet pressures at both ends of the core, atm; p0 is the atmospheric pressure, atm; L is the core length, cm; A is the cross-sectional area of ​​the core, cm2; μ is the viscosity of the fluid, mPa·s.

[0022] As a preferred technical solution of the present invention, a concentration of 10000 to 20000 mg / L of Mn 2+ The solution drives out the simulated formation water inside the core sample.

[0023] As a preferred technical solution of the present invention, the experimental simulation oil is prepared from kerosene and formation crude oil.

[0024] As a preferred technical solution of the present invention, the viscosity of the experimental simulated oil is the viscosity of the crude oil in the formation oil field of the oil reservoir where the core sample is located.

[0025] As a preferred technical solution of the present invention, the formation pressure and formation temperature are the formation pressure and formation temperature of the oil reservoir where the core sample is located.

[0026] As a preferred technical solution of the present invention, a mixed solution of toluene and ethanol is used to remove the asphaltene precipitation in the pore throats.

[0027] Compared with the prior art solutions, the present invention has at least the following beneficial effects:

[0028] The present invention provides an evaluation method for distinguishing changes in rock physical properties caused by CO2 extraction and dissolution. The evaluation method uses suitable chemical reagents to remove unnecessary substances in the core after displacement by cleaning according to the characteristics of the mineral components in the core, and then analyzes and distinguishes the changes in the core physical properties caused by organic (asphaltene) precipitation and inorganic (CO2-formation water-rock) interactions, thereby improving the accuracy of the evaluation method. BRIEF DESCRIPTION OF THE DRAWINGS

[0029] Figure 1 A schematic diagram of a structural evaluation system for distinguishing changes in rock properties caused by CO2 extraction and dissolution provided in a specific embodiment of the present invention

[0030] Figure 2 The relative changes in porosity of three rock samples with a permeability of 0.1 mD in Example 1 after displacement at different times due to organic precipitation and inorganic action;

[0031] Figure 3 The relative changes in permeability of three rock samples with a permeability of 0.1 mD in Example 1 after displacement at different times under the influence of organic precipitation and inorganic action;

[0032] Figure 4 The relative changes in porosity of three rock samples with a permeability of 0.1 mD in Example 1 after displacement of different times only affected by inorganic effects;

[0033] Figure 5 The relative changes in permeability of three rock samples with a permeability of 0.1 mD in Example 1 after displacement of different times and only affected by inorganic effects;

[0034] Figure 6 The relative changes in porosity of three rock samples with a permeability of 1 mD in Example 2 after displacement at different times due to organic precipitation and inorganic action;

[0035] Figure 7 The relative changes in permeability of three rock samples with a permeability of 1 mD in Example 2 after displacement at different times under the influence of organic precipitation and inorganic action;

[0036] Figure 8 The relative changes in porosity of the three rock samples with a permeability of 1 mD in Example 2 after displacement of different times only affected by inorganic effects;

[0037] Fig. 9 The relative changes in permeability of the three rock samples with a permeability of 1 mD in Example 2 after being displaced at different times and only affected by inorganic effects.

[0038] The present invention is further described in detail below. However, the following examples are only simplified examples of the present invention and do not represent or limit the scope of protection of the present invention. The scope of protection of the present invention shall be subject to the claims. DETAILED DESCRIPTION

[0039] The technical solution of the present invention is further described below with reference to the accompanying drawings and through specific implementation methods.

[0040] The specific embodiment of the present invention provides an evaluation method for distinguishing the changes in rock properties caused by CO2 flooding extraction and dissolution, and the evaluation method includes:

[0041] Using a core sample saturated with experimental simulated formation water that reaches the formation water salinity, measuring the permeability and porosity of the core sample;

[0042] Expelling simulated formation water from the core sample, heating the core sample to formation temperature, pressurizing the core sample to formation pressure, and saturating the core sample with experimental simulated oil until no water overflows;

[0043] Heating the core sample to the reservoir temperature, pressurizing the core sample to the reservoir pressure, and saturating the core sample with experimental simulated oil until no water overflows;

[0044] injecting CO2 into the core sample, and producing experimental simulated oil at bubble point pressure until no oil is produced;

[0045] The core sample is washed with n-heptane, and after displacing the fluid in the core sample, asphaltene precipitation in the pore throat is retained, and after drying, the permeability and porosity of the core sample affected by asphaltene precipitation and CO2-formation water-rock interaction are measured;

[0046] The asphaltene precipitates in the pore throats are removed, and after drying, the permeability and porosity of the core sample affected only by the CO2-formation water-rock interaction are measured.

[0047] In the present invention, since asphaltene is soluble in aromatic hydrocarbons but insoluble in alkanes, and other components in crude oil can be fully mixed with n-heptane, n-heptane is first used to remove the remaining fluid in the core after displacement and retain the asphaltene precipitate in the pore throat, and the core permeability and porosity jointly affected by the asphaltene precipitation and the CO2-formation water-rock interaction are measured after drying; the asphaltene precipitate is then removed, and the permeability and porosity of the core only affected by the CO2-formation water-rock interaction are measured after drying; this method not only obtains the influence law of organic precipitation and inorganic interaction on rock properties during CO2 displacement, but also obtains the influence of the core only on the CO2-formation water-rock interaction and the influence of the core only on the core physical properties by organic precipitation. This core evaluation system and method achieves the purpose of ultimately obtaining and distinguishing the influence of organic precipitation and inorganic action on core physical properties.

[0048] In a specific embodiment of the present invention, the method of using a core sample saturated with simulated formation water for experiment that reaches the mineralization of formation water can be: placing the core sample in a high-pressure saturation device, and evacuating the core for 48 hours to saturate it with simulated formation water.

[0049] In one embodiment of the present invention, a high concentration of Mn is used. 2+ The solution drives out the simulated formation water inside the core sample to eliminate the interference caused by the water signal. 2+ The solution may be a MnCl2 solution.

[0050] In a specific embodiment of the present invention, during the process of saturating the core sample with experimental simulated oil at the formation temperature and formation pressure as well as the reservoir temperature and reservoir pressure, no water overflow means that no water flows out from the outlet of the device where the core sample is located during the experiment.

[0051] In a specific embodiment of the present invention, a constant rate mode is used when the core sample is saturated with experimental simulated oil at the formation temperature and formation pressure as well as the reservoir temperature and reservoir pressure.

[0052] In a specific embodiment of the present invention, producing experimental simulated oil at bubble point pressure means that the outlet pressure of the device in which the core sample is located during the experiment is the bubble point pressure.

[0053] In one specific embodiment of the present invention, the volume ratio of toluene to ethanol can be 1:3.

[0054] In a specific embodiment of the present invention, the evaluation method further comprises calculating the porosity change rate and the permeability change rate, and the formula of the porosity change rate is:

[0055]

[0056] Where: l is the porosity change rate, %; φ0 is the initial porosity of the core sample, %; φ1 is the porosity of the core sample after the experiment, %;

[0057] The calculation formula of the permeability change rate is:

[0058]

[0059] Where: d is the permeability change rate, %; K0 is the initial permeability of the core sample, %; K1 is the permeability of the core sample after the experiment, %.

[0060] In one embodiment of the present invention, there is provided an evaluation system device for distinguishing the changes in rock properties caused by CO2 extraction and dissolution, the structure of which is as follows: Figure 1 As shown, the evaluation system device includes:

[0061] Core support device, CO2 storage device, experimental simulation oil storage device, Mn 2+ Solution storage device, simulated formation water storage device, ISCO pumping device and pressure control device;

[0062] The CO2 storage device, the experimental simulation oil storage device and the Mn 2+ The material outlet of the solution storage device is connected in parallel to the first inlet of the core holding device, and the CO2 storage device, the experimental simulation oil storage device and the Mn 2+ The material inlet of the solution storage device is connected in parallel with the ISCO pumping device; the simulated formation water storage device is connected to the second inlet of the core holding device, the simulated formation water storage device is connected to the first pumping device, and the core holding device is connected to the pressure control device;

[0063] The pressure control device includes a back pressure controller, a second pumping device and a gas storage device; the back pressure controller is connected to the core holding device, the second pumping device and the gas storage device are independently connected to the back pressure controller, and the gas storage device is connected to a gas flow meter.

[0064] To better illustrate the present invention and facilitate understanding of the technical solution of the present invention, typical but non-limiting embodiments of the present invention are as follows:

[0065] Example 1

[0066] This embodiment provides an evaluation method for distinguishing changes in rock properties caused by CO2 extraction and dissolution, and the evaluation method includes the following steps:

[0067] Step 1: Select three cores 0.1-3, 0.1-4 and 0.1-5 from an oil field in Changqing, and place the cores in an extraction container with a volume ratio of benzene to alcohol of 1:3 to wash the oil; after the oil washing is completed, place the cores in a constant temperature box and heat to 80°C to keep the temperature unchanged for 48 hours;

[0068] Step 2: Prepare simulated formation water with a mineralization of 12000 mg / L and Mn 2+ MnCl2 solution with ion concentration of 20000mg / L;

[0069] Step 3: prepare the experimental simulation oil according to the volume ratio of 1:3 of the reservoir crude oil and refined kerosene of a certain oil field in Changqing, and the viscosity reaches 12.37 mPa·s at 75.8°C;

[0070] Step 4: Place the core in a high-pressure saturation device, evacuate the core for 48 hours, and saturate it with simulated formation water. The permeability of the core before the experiment was measured to be 0.1 mD, and the porosity was 13.69%, 15.47%, and 14.48%, respectively;

[0071] Step 5: CO2 displacement device Figure 1 As shown, the simulated formation water was displaced with MnCl2 solution at a constant rate of 0.01 ml / min to eliminate the interference caused by the water signal;

[0072] Step 6: Heat the core holder to the formation temperature of 75.8°C, pressurize the core to the formation pressure of 19 MPa, and then saturate the core with formation crude oil at a constant rate (0.01 ml / min) until no water is produced at the outlet.

[0073] Step 7: Inject CO2 gas into the core at a constant rate of 0.01 ml / min, displace 1 PV, 2 PV and 6 PV of cores 0.1-3, 0.1-4 and 0.1-5 respectively, open the outlet valve, control the outlet pressure with a back pressure valve, keep it constant to the bubble point pressure, collect the output crude oil sample, and stop displacing when the core outlet does not produce oil;

[0074] Step 8: Wash the core with n-heptane to remove the remaining fluid in the core after displacement and retain the asphaltene precipitation in the pore throat. After drying, the core porosity change rate affected by asphaltene precipitation and CO2-formation water-rock interaction is -6.87%, -3.30%, and -6.17%. Figure 2 As shown, the permeability changes are -28.6%, -35.4%, and -52.4%. Figure 3 As shown in the figure, the porosity and permeability are reduced, indicating that the extraction and dissolution under CO2 flooding will lead to a decrease in the porosity and permeability of sandstone, resulting in a low permeability;

[0075] Step 9: Wash the core with toluene + ethanol to remove asphaltene precipitation. After drying, the porosity change rate of the core affected only by the interaction between CO2-formation water and rock is 6.43%, 5.69%, and 14.75%. Figure 4 As shown, the permeability changes are 52.1%, 46.3%, and 24.5%. Figure 5 This indicates that the interaction between CO2, formation water and rock increases the porosity and permeability, indicating that a certain amount of dissolution has occurred in the pores of the rock and some mineral particles have been taken out of the rock during the displacement process;

[0076] Step 10: According to Step 8 and Step 9, the porosity change rate of the core affected only by asphaltene precipitation is -13.3%, -8.99%, -20.92%, and the permeability change rate is -80.7%, -81.7%, -76.9%. The asphaltene precipitation produced during CO2 flooding has a damaging effect on the porosity and permeability of the core.

[0077] Example 2

[0078] This embodiment provides an evaluation method for distinguishing changes in rock properties caused by CO2 extraction and dissolution, and the evaluation method includes the following steps:

[0079] Step 1: Select three cores 1-3, 1-4 and 1-5 from an oil field in Changqing, and place the cores in an extraction container with a volume ratio of benzene to alcohol of 1:3 to wash the oil; after the oil washing is completed, place the cores in a constant temperature box and heat to 80°C to keep the temperature unchanged for 48 hours;

[0080] Step 2: Prepare simulated formation water with a mineralization of 12000 mg / L and Mn 2+ MnCl2 solution with ion concentration of 20000mg / L;

[0081] Step 3: prepare the experimental simulation oil according to the volume ratio of 1:3 of the reservoir crude oil and refined kerosene of a certain oil field in Changqing, and the viscosity reaches 10.48 mPa·s at 94.3°C;

[0082] Step 4: Place the core in a high-pressure saturation device, evacuate the core for 48 hours, and saturate it with simulated formation water. The permeability of the core before the experiment was measured to be 1mD, and the porosity was 14.26%, 7.04%, and 10.79%, respectively;

[0083] Step 5: CO2 displacement device Figure 1 As shown, the simulated formation water was displaced with MnCl2 solution at a constant rate of 0.01 ml / min to eliminate the interference caused by the water signal;

[0084] Step 6: Raise the temperature of the core holder to the formation temperature of 94.3°C, pressurize the core to the formation pressure of 24.3 MPa, and then saturate the core with formation crude oil at a constant rate (0.01 ml / min) until no water is produced at the outlet;

[0085] Step 7: Inject CO2 gas into the core at a constant rate of 0.01 ml / min, displace 1PV, 2PV and 6PV of cores 1-3, 1-4 and 1-5 respectively, open the outlet valve, control the outlet pressure with a back pressure valve, and keep it constant to the bubble point pressure, collect the output crude oil sample, and stop displacing when the core outlet does not produce oil;

[0086] Step 8: Wash the core with n-heptane to remove the remaining fluid in the core after displacement and retain the asphaltene precipitation in the pore throat. After drying, the core porosity change rate affected by asphaltene precipitation and CO2-formation water-rock interaction is -0.98%, -2.84%, and -20.2%. Figure 6 As shown. The permeability change rate is -5.32%, -2.35%, -15.2%, as shown Figure 7 As shown, the porosity and permeability are reduced, indicating that the extraction and dissolution under CO2 flooding will lead to a decrease in the porosity and permeability of sandstone;

[0087] Step 9: Wash the core with toluene + ethanol to remove asphaltene precipitation. After drying, the porosity change rate of the core affected only by the interaction between CO2-formation water and rock is 1.75%, 1.53%, and 1.76%. Figure 8 As shown, the permeability changes are 2.59%, 11.4%, and 9.3%. Fig. 9 This indicates that the interaction between CO2, formation water and rock increases the porosity and permeability, indicating that a certain amount of dissolution has occurred in the pores of the rock and some mineral particles have been taken out of the rock during the displacement process;

[0088] Step 10. According to Step 8 and Step 9, the porosity change rate of the core affected only by asphaltene precipitation is -2.73%, -4.37%, -21.96%, and the permeability change rate is -7.91%, -13.75%, -24.5%. The asphaltene precipitation produced during CO2 flooding has a damaging effect on the porosity and permeability of the core.

[0089] The applicant declares that the present invention illustrates the detailed structural features of the present invention through the above-mentioned embodiments, but the present invention is not limited to the above-mentioned detailed structural features, that is, it does not mean that the present invention must rely on the above-mentioned detailed structural features to be implemented. Those skilled in the art should understand that any improvement of the present invention, equivalent replacement of the components selected by the present invention, addition of auxiliary components, selection of specific methods, etc., all fall within the protection scope and disclosure scope of the present invention.

[0090] The preferred embodiments of the present invention are described in detail above. However, the present invention is not limited to the specific details in the above embodiments. Within the technical concept of the present invention, a variety of simple modifications can be made to the technical solution of the present invention, and these simple modifications all belong to the protection scope of the present invention.

[0091] It should also be noted that the various specific technical features described in the above specific embodiments can be combined in any suitable manner without contradiction. In order to avoid unnecessary repetition, the present invention will not further describe various possible combinations.

[0092] In addition, various embodiments of the present invention may be arbitrarily combined, and as long as they do not violate the concept of the present invention, they should also be regarded as the contents disclosed by the present invention.

Claims

1. A method for evaluating changes in rock properties caused by CO2 extraction and dissolution, characterized in that: The evaluation method includes: Using a core sample saturated with experimental simulated formation water that reaches the formation water salinity, measuring the permeability and porosity of the core sample; Expelling simulated formation water from the core sample, heating the core sample to formation temperature, pressurizing the core sample to formation pressure, and saturating the core sample with experimental simulated oil until no water overflows; The core sample is heated to the reservoir temperature, and the core sample is pressurized to the reservoir pressure, and the core sample is saturated with experimental simulated oil until no water overflows; injecting CO2 into the core sample, and producing experimental simulated oil at bubble point pressure until no oil is produced; The core sample is washed with n-heptane, and after displacing the fluid in the core sample, asphaltene precipitation in the pore throat is retained, and after drying, the permeability and porosity of the core sample affected by asphaltene precipitation and CO2-formation water-rock interaction are measured; The asphaltene precipitates in the pore throats are removed, and after drying, the permeability and porosity of the core sample affected only by the CO2-formation water-rock interaction are measured.

2. The evaluation method according to claim 1, characterized in that: Before using the experimental simulated formation water saturated core sample that reaches the formation water mineralization degree, the core sample is subjected to deoiling and drying treatments.

3. The evaluation method according to claim 1 or 2, characterized in that: The formation water mineralization is the formation water mineralization of the oil reservoir where the core sample is located.

4. The evaluation method according to any one of claims 1 to 3, characterized in that: The calculation formula of the permeability is: Where: φ is porosity, %; V p is the pore volume, cm3; V b is the total volume of the core, cm 3 .

5. The evaluation method according to any one of claims 1 to 4, characterized in that: The calculation formula of the porosity is: Where: Q0 is the volume flow rate under atmospheric pressure, cm / s; p1 and p2 are the inlet and outlet pressures at both ends of the core, atm; p0 is the atmospheric pressure, atm; L is the core length, cm; A is the cross-sectional area of ​​the core, cm2; μ is the viscosity of the fluid, mPa·s.

6. The evaluation method according to any one of claims 1 to 5, characterized in that: Use Mn at a concentration of 10,000 to 20,000 mg / L 2+ The solution drives out the simulated formation water inside the core sample.

7. The evaluation method according to any one of claims 1 to 6, characterized in that: The experimental simulation oil is prepared from kerosene and formation crude oil.

8. The evaluation method according to claim 7, characterized in that: The viscosity of the experimental simulated oil is the viscosity of the crude oil in the formation oil field of the oil reservoir where the core sample is located.

9. The evaluation method according to any one of claims 1 to 8, characterized in that: The formation pressure and formation temperature are the formation pressure and formation temperature of the oil reservoir where the core sample is located.

10. The evaluation method according to any one of claims 1 to 9, characterized in that: A mixed solution of toluene and ethanol is used to remove asphaltene precipitation in the pore throats.

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