A method for characterizing the wettability of reservoir rocks under simulated production conditions

Abstract

The present invention discloses a method for characterizing the wettability of reservoir rocks under simulated production conditions, which comprises the following steps: completely saturating a rock sample with a manganese chloride solution and testing the nuclear magnetic resonance T<subgt;1< / subgt>-T<subgt;2< / subgt> spectrum curve of the rock sample; displacing the rock sample with formation crude oil to the irreducible water state, aging it at the formation temperature and then measuring the T<subgt;1< / subgt>-T<subgt;2< / subgt> spectrum curve; conducting waterflooding experiments on the aged rock sample under different simulated production pressure differences respectively and measuring the T<subgt;1< / subgt>-T<subgt;2< / subgt> spectrum curves of the rock sample after each stage of displacement pressure difference; extracting the T<subgt;2 spectrum curves after complete water saturation, irreducible water saturation and each stage of displacement pressure difference; determining the initial wettability of the rock sample according to the shift of the T<subgt;2 spectrum curves between the irreducible water state and the completely water-saturated state; and determining the wettability of the rock sample under each stage of displacement pressure difference according to the shift of the T<subgt;2 spectrum curves after each stage of displacement pressure difference and under complete water saturation. The present invention can determine the wettability of reservoir rocks and its variation characteristics at different production stages, making up for the deficiency that the existing wettability schemes cannot dynamically monitor wettability.

Description

Technical Field

[0001] The present invention relates to a method for characterizing the wettability of reservoir rocks under simulated production conditions, belonging to the technical field of oil and gas exploration and development. Background Art

[0002] The wettability of reservoir rocks refers to the spreading ability or tendency of one of the two-phase fluids on the rock surface when there are two-phase fluids in the pore space of the rock. The wettability of reservoir rocks is one of the most basic physical properties of the reservoir, and it is a key factor affecting the microscopic distribution of oil and water in the pore space of reservoir rocks, the seepage characteristics of fluids in the pore space, and the oil and water saturations in the oil reservoir.

[0003] During the development process of oil and gas reservoirs, there are a large number of fluid displacement processes in reservoir rocks, which will cause the properties of fluids to change continuously. Therefore, the wettability of rocks will change with different development stages. The commonly used wettability evaluation methods, such as the contact angle method, the Amott method, and the USBM method, can only characterize the wettability of rocks in the initial state or the final state, and it is difficult to characterize the dynamic changes in the wettability of rocks during the development of oil reservoirs. Currently, there are still few studies on the dynamic changes in the wettability of reservoir rocks, and a complete set of dynamic wettability evaluation processes or experimental methods has not been formed yet. Nuclear magnetic resonance, as a technology that can accurately, quickly, and non-destructively obtain the interaction information between fluid molecules and the pore surface of rocks, provides the possibility for judging the wetting properties of the pore surface of rocks.

[0004] The present method provides a dynamic wettability evaluation method based on nuclear magnetic resonance technology, which can accurately characterize the dynamic changes in the wettability of reservoir rocks under production conditions, and is of great significance for the reasonable adjustment of oil reservoir development plans at different stages and the implementation of enhanced oil recovery plans. Summary of the Invention

[0005] In order to overcome the problems and deficiencies in the prior art, the present invention provides a method for characterizing the wettability of reservoir rocks under simulated production conditions, and the present invention realizes the dynamic characterization of wettability.

[0006] The technical solution provided by the present invention to solve the above technical problems is: a method for characterizing the wettability of reservoir rocks under simulated production conditions, comprising the following steps:

[0007] Step S1: Select a plug rock sample. After washing the plug rock sample with oil and drying it, measure the dry weight, length, diameter, porosity, and permeability of the rock sample with reference to relevant industry standards, and record them as m0, L, D, φ He and K;

[0008] Step S2: Place the rock sample in an intermediate container and perform vacuum pressure saturation with a manganese chloride solution of a certain concentration. After 48 hours, take out the rock sample and weigh it, recording it as m1. Calculate the effective porosity of the rock sample according to formula (1) and formula (2). When the obtained effective porosity and the porosity obtained with reference to the industry standard satisfy formula (3), it is determined that the rock sample has been vacuum saturated to the requirement. If it does not satisfy formula (3), it is determined that the rock sample has not been vacuum saturated to the requirement, and the rock sample needs to be resaturated until it satisfies formula (3). After it is fully saturated, measure and obtain the nuclear magnetic resonance T1-T2 spectrum curve of the saturated manganese chloride solution of the rock sample.

[0009]

[0010] Where: V peff ——Effective pore volume of rock sample, cm 3 ;

[0011] m1, m0 - the mass of the rock sample after saturation and before saturation, g;

[0012] ρ——density of the fluid used for saturation, g / cm 3 ;

[0013] φ p ——effective porosity of the rock sample, decimal;

[0014] V——total volume of rock sample, cm 3 .

[0015] Step S3: placing the saturated rock sample into a rock sample holder and connecting it to a displacement device, displacing the rock sample with formation crude oil until no water is produced, and then stopping the displacement experiment; immersing the rock sample after displacement in formation crude oil and aging it at formation temperature for no less than 10 days; after aging, measuring the nuclear magnetic resonance T1-T2 spectrum curve of the rock sample in the bound water state;

[0016] Step S4: placing the aged rock sample into a rock sample holder, and conducting a flooding experiment with a certain concentration of manganese chloride aqueous solution configured in advance under different displacement pressure differences, wherein the setting of each displacement pressure difference is determined according to the production pressure difference of the reservoir where the rock sample is located, including at least four displacement pressure differences, and the displacement pressure difference increases step by step in the water flooding experiment; each displacement pressure difference is driven until no more oil is produced, and the displacement is stopped, and the nuclear magnetic resonance T1-T2 spectrum curve of the rock sample is measured at the corresponding time, and finally the nuclear magnetic resonance T1-T2 spectrum curve of the rock sample under each displacement pressure difference is obtained;

[0017] Step S5, extracting the T2 spectrum curves of the NMR water phase in the fully saturated water state, the bound water state, and the displacement pressure difference at each level from the corresponding NMR T1-T2 spectrum curves;

[0018] Step S6: Calculate the geometric mean of T2 of the rock sample when it is completely saturated with manganese chloride solution and in the bound water state according to Equations (4) and (5), and calculate the NMR T2 spectrum deviation degree of the reservoir rock according to Equation (6) to obtain the initial wettability of the reservoir rock;

[0019]

[0020]

[0021] where: T 2gm —— Geometric mean of the transverse relaxation time, ms;

[0022] φ NMR —— NMR porosity of the rock sample, decimal;

[0023] A —— Signal size of the NMR T2 spectrum, dimensionless;

[0024] a, b —— Calibration coefficients, dimensionless;

[0025] V —— Total volume of the rock sample, cm 3 ;

[0026] T2 —— NMR transverse relaxation time, ms;

[0027] T 2gm(0) —— Geometric mean of the transverse relaxation time when completely saturated with water, ms;

[0028] T 2gm(i) —— Geometric mean of the transverse relaxation time in different states, ms;

[0029] I —— Deviation degree of the NMR T2 spectrum, dimensionless.

[0030] Step S7: Calculate the geometric mean of T2 of the rock sample after water flooding at different displacement pressure differences according to Equations (4) and (5), calculate the NMR T2 spectrum deviation degree of the reservoir rock at different water flooding stages, and obtain the change of wettability of the reservoir rock according to the evaluation criteria in Table 1;

[0031] Table 1 Wettability evaluation criteria

[0032]

[0033] A further technical solution is that the mass concentration of the manganese chloride solution with a certain concentration in Step S2 is 4 - 10 g / L.

[0034] A further technical solution is that the experimental oil in Step S3 is formation crude oil or the crude oil required for research.

[0035] A further technical solution is that in step S3, the nuclear magnetic resonance T1-T2 spectrum of the rock sample in the bound water state measured should show separated water-phase T2 spectral curves and oil-phase T2 spectral curves; if the T2 spectral curves of the water phase and the oil phase cannot be separated, adjust the mass concentration of the manganese chloride solution and repeat steps S2 and S3 until the T2 spectral curves of the water phase and the oil phase are separated.

[0036] A further technical solution is that in steps S6 and S7, the nuclear magnetic resonance water-phase T2 spectral curves after water flooding with different displacement pressure differences are used to calculate the degree of deviation from the nuclear magnetic resonance T2 spectral curve in the fully water-saturated state, so as to obtain the initial wettability of the reservoir rock and the wettability under different displacement pressure differences. The present invention has the following beneficial effects:

[0037] The present invention utilizes the characteristics of two-dimensional nuclear magnetic resonance technology to accurately, quickly, and non-destructively measure the fluid saturation in the rock sample, and preferably selects the concentration that can separate the water-phase and oil-phase signals in the nuclear magnetic resonance T1-T2 spectrum, and uses the manganese chloride solution with this concentration in the subsequent experimental water. Saturate the rock sample with a certain concentration of manganese chloride solution, establish the irreducible water saturation through oil displacement and aging, and then carry out water flooding experiments with different displacement pressure differences. Then, obtain the nuclear magnetic resonance T1-T2 spectral curves of the rock sample after each displacement experiment, and extract the nuclear magnetic resonance T2 spectra of the oil phase and the water phase from them. Calculate the initial wettability of the reservoir rock according to the degree of deviation of the nuclear magnetic resonance T2 spectral curves in the irreducible water and fully water-saturated states, and then calculate the change characteristics of the wettability of the reservoir rock with different production stages according to the degree of deviation of the spectral curves after water flooding with different displacement pressure differences from the nuclear magnetic resonance T2 curve in the fully water-saturated state.

[0038] This method determines the change of the wettability of the reservoir rock at different production stages, realizes the dynamic detection of wettability, and makes up for the deficiencies of the existing wettability evaluation methods. The invention also has the beneficial effects of simple process, short experimental time, and accurate evaluation results. BRIEF DESCRIPTION OF THE DRAWINGS

[0039] In order to more clearly illustrate the technical solutions in the embodiments of the present invention, the following will briefly introduce the drawings required in the embodiments. Obviously, the drawings in the following description are only some embodiments of the present invention. For those of ordinary skill in the art, without creative efforts, other drawings can be obtained based on these drawings.

[0040] Figure 1 It is the specific implementation process of the method of the present invention; DETAILED DESCRIPTION OF THE INVENTION

[0041] The technical solution of the present invention will be clearly and completely described below with reference to the accompanying drawings. Apparently, the described embodiments are some but not all of the embodiments of the present invention. All other embodiments obtained by those of ordinary skill in the art based on the embodiments of the present invention without creative efforts shall fall within the protection scope of the present invention.

[0042] As Figure 1 shown, a method for characterizing the wettability of reservoir rocks under simulated production conditions includes the following steps:

[0043] Step S1: Select a cylindrical rock sample with a length greater than 4 cm. After washing the oil and drying the cylindrical rock sample, measure the dry weight, length, diameter, porosity, and permeability of the rock sample according to the regulations in the national standard GB / T 29172-2012 "Rock Sample Analysis Method", and record them as m0, L, D, φ He and K;

[0044] Step S2: Place the rock sample in an intermediate container, evacuate and pressurize it to saturate it with a manganese chloride solution of a certain concentration for 48 hours, then take it out and weigh it as m1, and calculate the effective porosity of the rock sample according to formulas (1) and (2);

[0045]

[0046] In the formula: V peff ——The effective pore volume of the rock sample, cm 3 ;

[0047] m1, m0——The mass of the rock sample after and before saturation, g;

[0048] ρ——The density of the fluid used for saturation, g / cm 3 ;

[0049] φ p ——The effective porosity of the rock sample, decimal;

[0050] V——The total volume of the rock sample, cm 3 .

[0051] Step S3: When the obtained effective porosity meets formula (3) with the porosity obtained by referring to the industry standard, it is determined that the evacuation and saturation of the rock sample meet the requirements; if it does not meet formula (3), it is determined that the evacuation and saturation of the rock sample do not meet the requirements, and the rock sample needs to be resaturated until it meets formula (3); after complete saturation, measure and obtain the nuclear magnetic resonance T1-T2 spectrum curve of the rock sample saturated with manganese chloride solution;

[0052]

[0053] Step S4: Load the saturated rock sample into the rock sample holder, connect the displacement device, and displace the rock sample with formation crude oil until water production stops, then terminate the displacement experiment; Immerse the rock sample after displacement in the formation crude oil and age it for at least 10 days under formation temperature conditions with reference to relevant industry standards; After aging is completed, obtain the nuclear magnetic resonance T1-T2 spectral curve of the rock sample in the irreducible water state.

[0054] Step S5: Load the rock sample after aging into the rock sample holder, and conduct a manganese chloride solution oil displacement experiment under a displacement pressure difference of 0.6 MPa; Terminate the displacement experiment when oil production stops, and test and obtain the nuclear magnetic resonance T1-T2 spectral curve of the rock sample.

[0055] Step S6: Reload the rock sample into the rock sample holder, and conduct a manganese chloride solution oil displacement experiment under a displacement pressure difference of 1.2 MPa; Terminate the displacement experiment when oil production stops, and test and obtain the nuclear magnetic resonance T1-T2 spectral curve of the rock sample.

[0056] Step S7: Reload the rock sample into the rock sample holder, and conduct a manganese chloride solution oil displacement experiment under a displacement pressure difference of 2.5 MPa; Terminate the displacement experiment when oil production stops, and test and obtain the nuclear magnetic resonance T1-T2 spectral curve of the rock sample.

[0057] Step S8: Reload the rock sample into the rock sample holder, and conduct a manganese chloride solution oil displacement experiment under a displacement pressure difference of 4.5 MPa; Terminate the displacement experiment when oil production stops, and test and obtain the nuclear magnetic resonance T1-T2 spectral curve of the rock sample.

[0058] Step S9: Extract the T2 spectral curves of the nuclear magnetic resonance water phase in the fully saturated water state, irreducible water state, and after each stage of displacement pressure difference from the corresponding nuclear magnetic resonance T1-T2 spectral curves.

[0059] Step S10: Calculate the nuclear magnetic resonance T2 geometric mean of the rock sample in different states according to Equations (4) and (5).

[0060]

[0061] where: T 2gm —— Geometric mean of the transverse relaxation time, ms;

[0062] φ NMR —— Nuclear magnetic porosity of the rock sample, decimal;

[0063] A—— Magnitude of the nuclear magnetic resonance T2 spectral signal, dimensionless;

[0064] a, b—— Calibration coefficients, dimensionless;

[0065] V—— Total volume of the rock sample, cm 3 ;

[0066] T2—the transverse relaxation time of nuclear magnetic resonance, ms;

[0067] Step S11: Calculate the offset degree of the nuclear magnetic resonance T2 spectrum of the reservoir rock in the irreducible water state, after water flooding at different displacement pressure differences, and in the initial fully saturated water state according to Equation (6), and obtain the change characteristics of the wettability of the reservoir rock.

[0068]

[0069] In the formula: I—the offset degree of the nuclear magnetic resonance T2 spectrum, dimensionless.

[0070] T 2gm(0) —the geometric mean of the transverse relaxation times of fully saturated water, ms;

[0071] T 2gm(i) —the geometric mean of the transverse relaxation times in different states, ms;

[0072] As mentioned above, it is not any form of limitation to the present invention. Although the present invention has been disclosed by the above embodiments, it is not intended to limit the present invention. Any person skilled in the art can make changes or modifications using the disclosed technical content within the scope of the technical solution of the present invention as equivalent embodiments of equivalent changes. However, any simple modification, equivalent change and modification made to the above embodiments based on the technical essence of the present invention still fall within the scope of the technical solution of the present invention.

Claims

1. A method for characterizing the wettability of reservoir rocks under simulated production conditions, characterized in that, Specifically, it includes the following steps: Step S1: Select a plug rock sample. After washing the oil and drying the plug rock sample, measure the dry weight, length, diameter, porosity, and permeability of the rock sample with reference to relevant industry standards, and record them as m0, L, D, φ He and K respectively; Step S2: Place the rock sample into an intermediate container, evacuate and pressurize it to saturate it with a manganese chloride solution of a certain concentration for 48 hours, then take it out and weigh it as m1. Calculate the effective porosity of the rock sample according to Equations (1) and (2). When the effective porosity of the rock sample and the porosity obtained according to the reference industry standard satisfy Equation (3), it is determined that the evacuation and saturation of the rock sample meet the requirements. If Equation (3) is not satisfied, it is determined that the evacuation and saturation of the rock sample do not meet the requirements, and the rock sample needs to be resaturated until Equation (3) is satisfied. After complete saturation, measure and obtain the nuclear magnetic resonance T1-T2 spectrum curve of the rock sample saturated with the manganese chloride solution at the same time; Where: V peff —— The effective pore volume of the rock sample, cm 3 ; m1, m0——The masses of the rock sample after and before saturation, g; ρ——Density of the fluid used for saturation, g / cm 3 ; φ p —— Effective porosity of rock sample, fraction; V—the total volume of the rock sample, cm 3 ; Step S3: Place the saturated rock sample into a rock sample holder, connect the displacement device, and displace the rock sample with formation crude oil until the water production stops, then stop the displacement experiment. Immerse the rock sample after displacement in the formation crude oil and age it for at least 10 days under formation temperature conditions. After aging is completed, measure the nuclear magnetic resonance T1-T2 spectrum curve of the rock sample in the irreducible water state; Step S4: Place the rock sample after aging into a rock sample holder, and carry out the oil displacement experiment with a manganese chloride aqueous solution of a certain concentration prepared in advance under each displacement pressure difference. The setting of each displacement pressure difference is determined according to the production pressure difference of the reservoir where the rock sample is located, including at least 4 displacement pressure differences, and the displacement pressure difference increases gradually during the water flooding experiment. At each displacement pressure difference, displace until no more oil is produced, then stop the displacement, and measure the nuclear magnetic resonance T1-T2 spectrum curve of the rock sample at that time. Finally, obtain the nuclear magnetic resonance T1-T2 spectrum curves of the rock sample under each displacement pressure difference; Step S5: Extract the T2 spectrum curves of the nuclear magnetic resonance aqueous phase in the fully saturated water state, irreducible water state, and after each displacement pressure difference from the corresponding nuclear magnetic resonance T1-T2 spectrum curves; Step S6: Calculate the T2 geometric mean of the rock sample in the state of being fully saturated with the manganese chloride solution and in the irreducible water state according to Equations (4) and (5), calculate the nuclear magnetic resonance T2 spectrum deviation degree of the reservoir rock according to Equation (6), and obtain the initial wettability of the reservoir rock according to the wettability evaluation criteria in Table 1; Where: T 2gm —— Geometric mean of the transverse relaxation time, ms; φ NMR ——Nuclear magnetic porosity of rock sample, decimal; A——The magnitude of the nuclear magnetic resonance T2 spectrum signal, dimensionless; a, b——Calibration coefficients, dimensionless; V—the total volume of the rock sample, cm 3 ; T2——The nuclear magnetic resonance transverse relaxation time, ms; T 2gm(0) —— Geometric mean of the transverse relaxation time of fully saturated water, ms; T 2gm(i) —— Geometric mean of the transverse relaxation times in different states, ms; I——The deviation degree of the nuclear magnetic resonance T2 spectrum of the reservoir rock, dimensionless; Step S7: Calculate the T2 geometric mean of the rock sample after water flooding under different displacement pressure differences according to Equations (4) and (5), calculate the nuclear magnetic resonance T2 spectrum deviation degree of the reservoir rock at each water flooding stage according to Equation (6), and obtain the change in the wettability of the reservoir rock according to the evaluation criteria in Table 1; Table 1 Wettability evaluation criteria 2. The wettability characterization method for reservoir rocks under simulated production conditions according to claim 1, wherein In Step S1, the length of the plug rock sample is 4 - 5 cm, and the diameter is 2.5 cm.

3. The wettability characterization method under simulated production conditions of a reservoir rock according to claim 1, characterized in that In Step S2, the mass concentration of the manganese chloride solution of a certain concentration is 4 - 10 g / L.

4. The wettability characterization method under simulated production conditions of a reservoir rock according to claim 1, characterized in that, The experimental oil in Step S3 is formation crude oil or the crude oil required for research.

5. A wettability characterization method for reservoir rocks under simulated production conditions according to claim 1, characterized in that In Step S3, the nuclear magnetic resonance T1-T2 spectrum of the rock sample in the irreducible water state measured should show separated T2 spectrum curves of the water phase and the oil phase; If the T2 spectral curves of the water phase and the oil phase cannot be separated, adjust the mass concentration of the manganese chloride solution and repeat steps S2 and S3 until the T2 spectral curves of the water phase and the oil phase are separated.

6. The wettability characterization method under simulated production conditions of a reservoir rock according to claim 1, wherein In steps S6 and S7, the offset degree between the nuclear magnetic resonance water phase T2 spectral curve after water flooding with different displacement pressure differences and the nuclear magnetic resonance T2 spectral curve in the fully saturated water state is calculated to obtain the initial wettability of the reservoir rock and the wettability under different displacement pressure differences.

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