Method for continuously monitoring fluid in rock sample imbibition process

Abstract

The invention discloses a method for continuously monitoring fluid in a rock sample imbibition process, and belongs to the technical field of petroleum engineering. The method for continuously monitoring the fluid in the rock sample imbibition process comprises the following steps: S1, testing T2-T1 spectrums of a saturated rock sample and an oil sample of the saturated rock sample by using a nuclear magnetic resonance technology; testing a T2-T1 spectrum of a free oil phase and a T2-T1 spectrum of simulated formation water by using a nuclear magnetic resonance technology; s2, the saturated rock sample is placed in an imbibition container containing simulated formation water for imbibition, T2-T1 spectrum nuclear magnetism testing is carried out, the total porosity phi total corresponding to a total fluid signal in the rock core and the strength of a mixed fluid signal outside the rock core are calculated, oil and water components are distinguished by combining a T2-T1 threshold value, and the content of remaining oil and the content of intrusive water are quantified. According to the method provided by the invention, dynamic continuous monitoring and accurate quantification of the imbibition process are realized.

Description

Technical Field

[0001] The present invention relates to the technical field of petroleum engineering, and in particular to a method for continuous monitoring of fluid in a rock sample imbibition process. Background Art

[0002] Core imbibition experiments are a core method for studying the spontaneous replacement of fluids in porous media. Their results are of great significance for reservoir evaluation and the formulation of enhanced oil recovery strategies. Nuclear magnetic resonance (NMR) technology, due to its non-destructive nature, has been widely used to characterize fluid dynamics in imbibition experiments. However, current NMR-based imbibition experimental methods have significant limitations: to obtain fluid data within the core, the core must be removed from the imbibition fluid multiple times during the imbibition process and subjected to NMR measurements. This interruptive operation raises multiple issues: First, removing the core interrupts the imbibition process, forming a liquid-gas interface on the core surface. External gas invades the pores and alters the capillary pressure balance, causing subsequent imbibition paths to deviate from the actual reservoir environment. Second, wiping the liquid off the core surface can easily cause fluid loss, disrupting the mass conservation condition and leading to cumulative deviations between the NMR signal amplitude and the actual imbibition volume.

[0003] In response to the above problems, researchers have tried to improve the experimental methods. Wang Biao and others developed a shale gas-liquid collaborative imbibition experimental system, combining one-dimensional nuclear magnetic resonance and Raman spectroscopy technology to invert the water saturation of the core through conductivity parameters. However, this method still relies on periodic interruption experiments for nuclear magnetic measurements, and the Raman spectral signals of multi-component fluids are prone to overlap, resulting in insufficient fluid identification resolution and an inability to accurately characterize the continuous dynamic changes of the fluid inside the core during the imbibition process. In response to the above defects, the present invention proposes a continuous monitoring method based on two-dimensional nuclear magnetic resonance, which realizes dynamic tracking and quantitative analysis of fluid changes during the imbibition process through non-interrupted real-time data acquisition and precise identification of fluids using T2-T1 two-dimensional spectra, thereby solving the problems of discontinuous data, fuzzy component distinction and insufficient quantification accuracy in the existing technology. Summary of the Invention

[0004] To address the limitations of NMR measurements during interrupted imbibition experiments, this paper proposes a method for continuous fluid monitoring during the imbibition process of rock samples, which is crucial for providing more accurate, comprehensive, and efficient experimental data. This innovative method utilizes multidimensional NMR characterization, employing T2-T1 two-dimensional NMR technology to accurately distinguish between fluids in different states, such as bound water and free water. This method also combines a combined porosity-saturation calculation method to determine the content of multiphase fluids.

[0005] The purpose of the present invention is to overcome the above technical deficiencies, provide a method for monitoring fluid changes inside rock samples, and solve the technical problems of data discontinuity, fuzzy component differentiation and insufficient quantification accuracy in the prior art.

[0006] To achieve the above technical objectives, the technical solution of the present invention provides a method for continuous monitoring of fluid during rock sample imbibition, comprising the following steps:

[0007] S1. Use nuclear magnetic resonance technology to test the T2-T1 spectra of saturated rock samples and oil samples in saturated rock samples; use nuclear magnetic resonance technology to test the T2-T1 spectrum of free oil phase and the T2-T1 spectrum of simulated formation water;

[0008] S2. Place the saturated rock sample in an imbibition container filled with simulated formation water for imbibition, and perform T2-T1 nuclear magnetic resonance testing to calculate the total porosity (φ) corresponding to the total fluid signal inside the rock sample. 总 ) and the signal intensity of the mixed fluid outside the rock sample, combined with the T2-T1 threshold to distinguish the oil and water components and quantify the remaining oil and invaded water content.

[0009] In any embodiment, in step S1, a T2-T1 two-dimensional spectrum test is performed on the oil-saturated rock sample, the original signal is converted into a T2-T1 two-dimensional distribution spectrum by an inversion algorithm, and the total porosity (φ) is calculated by double integration of the T2-T1 two-dimensional spectrum. 总 ), the calculation formula is obtained from (2):

[0010] (2)

[0011] Where φ 总 is the total porosity of the rock sample, T1 and T2 are the longitudinal relaxation time and transverse relaxation time respectively, P(T2, T1) is the two-dimensional distribution function of T2-T1, which represents the joint probability density of relaxation time, dT1 and dT2 are the small changes of T1 and T2, Integrate the corresponding variable from 0 to positive infinity.

[0012] In any embodiment, in step S1, the initial saturation S of the oil sample of the saturated rock sample is 油初 and initial content F 油初 They are calculated by the following formulas:

[0013] S 油初 = φ 油 / φ 总 (3)

[0014] F 油初 = S 油初 ×φ 总 ×V 岩 (4)

[0015] Where S 油初 is the initial saturation of the oil phase, φ 油 is the porosity of the oil phase, φ 总 is the total porosity of the rock sample; where F油初 is the initial content of oil phase in the rock sample, S 油初 is the initial saturation of the oil phase, φ 总 is the total porosity of the rock sample; V 岩 is the volume of the rock sample.

[0016] In any embodiment, in step S2, the external oil content F of the rock sample during the imbibition stage is 油外 Calculated by the following formula:

[0017] F 油外 =A 油占比 × (I 总 / I o ) (5)

[0018] Where F 油外 is the external oil content of the rock sample, A 油占比 is the oil phase peak area ratio, I 总 is the total mixed signal intensity; I o is the signal intensity per unit volume of the oil phase.

[0019] In any embodiment, in step S1, the oil phase is n-dodecane.

[0020] In any embodiment, in step S1, the volume of the oil sample saturating the rock sample is calculated by the following formula:

[0021] V 油初 = (W 饱和油 -W 干岩 ) / ρ 油 (1)

[0022] Where V 油初 is the volume of the oil phase in the saturated oil sample, W 饱和油 is the weight of the oil-saturated rock sample, W 干岩 is the weight of the dried rock sample, ρ 油 is the density of oil.

[0023] In any embodiment, in step S1, the initial oil content of the saturated rock sample is calculated by the following formula:

[0024] S 油初 = φ 油 / φ 总 (3)

[0025] Where S 油初 is the initial saturation of the oil phase, φ 油 is the porosity of the oil phase, φ 总 is the total porosity of the rock sample;

[0026] F 油初 = S油初 ×φ 总 ×V 岩 (4)

[0027] Where F 油初 is the initial content of oil phase in the rock sample, S 油初 is the initial saturation of the oil phase, φ 总 is the total porosity of the rock sample; V 岩 is the volume of the rock sample.

[0028] In any embodiment, in step S2, the remaining oil content is calculated as F 油剩余 =F 油初 -F 油外 Among them, F 油初 is the initial content of oil phase in the rock sample, F 油外 is the external oil content of the rock sample, and the intrusion water content is calculated as F 水侵 =F 总 -F 油剩余 , where F 总 It is the total fluid content inside the rock sample during the imbibition stage, and is combined with the T1 / T2 threshold to verify the water phase signal area.

[0029] In any embodiment, in step S1, the saturated rock sample is prepared by the following steps: placing the dried rock sample in a vacuum pressurization saturation device, first evacuating the sample to an absolute pressure to remove residual gas in the pores; then pressurizing the sample to a set pressure and maintaining the pressure constant; then monitoring the reading of the pressure gauge, and pressurizing and saturating the sample for more than one week to fully saturate the rock sample with fluid.

[0030] In any embodiment, in step S1 or S2, the rock sample is a rock core, and the rock core is a standard rock core plug sample used in a laboratory.

[0031] Compared with the existing technology, the beneficial effects of the present invention include: the method for continuous monitoring of fluid in the rock sample imbibition process proposed in the present invention achieves portable and accurate monitoring of the rock sample imbibition process through continuous imbibition experiments in conjunction with two-dimensional nuclear magnetic resonance technology, breaking through the limitations of traditional interrupted measurements, realizing dynamic continuous monitoring and precise quantification of the imbibition process, and providing an efficient technical means for oil and gas reservoir fluid research. BRIEF DESCRIPTION OF THE DRAWINGS

[0032] Figure 1 It is a schematic structural diagram of the imbibition device of Example 1 of the present invention.

[0033] Figure 2 It is a flow chart of the method for monitoring changes in fluid inside a rock sample according to Example 1 of the present invention.

[0034] Figure 3 This is a two-dimensional nuclear magnetic resonance fluid identification diagram of Example 1 of the present invention.

[0035] Explanation of the accompanying symbols: 1. imbibition container; 2. oil-saturated core; 3. imbibition solution. DETAILED DESCRIPTION

[0036] The "range" disclosed in this application is defined in the form of a lower limit and an upper limit. A given range is defined by selecting a lower limit and an upper limit, and the selected lower limit and upper limit define the boundaries of a particular range. The range defined in this way can be inclusive or exclusive of the end values, and can be arbitrarily combined, i.e., any lower limit can be combined with any upper limit to form a range. For example, if a range of 60 to 120 and 80 to 110 is listed for a particular parameter, it is understood that a range of 60 to 110 and 80 to 120 is also expected. In addition, if the minimum range values listed are 1 and 2, and if the maximum range values listed are 3, 4, and 5, then the following ranges can all be expected: 1 to 3, 1 to 4, 1 to 5, 2 to 3, 2 to 4, and 2 to 5. In this application, unless otherwise specified, the numerical range "a to b" represents an abbreviation of any real number combination between a and b, wherein a and b are both real numbers. For example, a numerical range of "0-5" indicates that all real numbers between "0-5" are listed herein, and "0-5" is simply an abbreviation for these numerical combinations. Furthermore, stating that a parameter is an integer ≥ 2 is equivalent to disclosing that the parameter is, for example, an integer of 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, etc.

[0037] Unless otherwise specified, the terms "include" and "comprising" used in this application may be open-ended or closed-ended. For example, "include" and "comprising" may mean that other components not listed may also be included or that only the listed components are included.

[0038] Unless otherwise specified, the term "or" is used in this application to be inclusive. For example, the phrase "A or B" means "A, B, or both A and B." More specifically, the condition "A or B" is satisfied if any of the following conditions are met: A is true (or exists) and B is false (or does not exist); A is false (or does not exist) and B is true (or exists); or both A and B are true (or exist).

[0039] This specific embodiment provides a method for continuous monitoring of fluid during rock sample imbibition, comprising the following steps:

[0040] S1. Using nuclear magnetic resonance technology to measure the T2-T1 spectra of saturated rock samples and oil samples of saturated rock samples; using nuclear magnetic resonance technology to measure the T2-T1 spectrum of free oil phase and T2-T1 spectrum of simulated formation water, recording the positions of characteristic peaks, and establishing a two-dimensional nuclear magnetic resonance identification reference map of free oil phase and water phase; the oil phase is n-dodecane;

[0041] The volume of the oil sample saturated with the rock sample is calculated by the following formula:

[0042] V 油初 = (W 饱和油 -W 干岩 ) / ρ 油 (1)

[0043] Where V 油初 is the volume of the oil phase in the saturated oil sample, W 饱和油 is the weight of the oil-saturated rock sample, W 干岩 is the weight of the oven-dried rock sample, ρ 油 is the density of oil;

[0044] The T2-T1 two-dimensional spectrum test is carried out on the oil-saturated rock sample. The original signal is converted into a T2-T1 two-dimensional distribution spectrum through the inversion algorithm. The total porosity (φ 总 ), the calculation formula is obtained from (2):

[0045] (2)

[0046] Where φ 总 is the total porosity of the rock sample, T1 and T2 are the longitudinal relaxation time and transverse relaxation time respectively, P(T2, T1) is the two-dimensional distribution function of T2-T1, which represents the joint probability density of relaxation time, dT1 and dT2 are the small changes of T1 and T2, Integrate the corresponding variable from 0 to positive infinity;

[0047] The initial saturation S of the oil sample of the saturated rock sample 油初 and initial content F 油初 They are calculated by the following formulas:

[0048] S 油初 = φ 油 / φ 总 (3)

[0049] F 油初 = S 油初 ×φ 总 ×V 岩 (4)

[0050] Where S 油初 is the initial saturation of the oil phase, φ 油 is the porosity of the oil phase, φ 总 is the total porosity of the rock sample; where F 油初 is the initial content of oil phase in the rock sample, S 油初 is the initial saturation of the oil phase, φ 总 is the total porosity of the rock sample; V岩 is the volume of the rock sample.

[0051] S2. Place the saturated rock sample in an imbibition container filled with simulated formation water for imbibition. Ensure that the rock sample is completely immersed and does not touch the container wall. At any time point after the imbibition begins, directly place the imbibition container into the nuclear magnetic resonance instrument probe to perform T2-T1 two-dimensional spectrum testing, obtain the two-dimensional spectrum of this stage, and calculate the total porosity (φ) corresponding to the total fluid signal inside the rock sample. 总 ) and the signal intensity of the mixed fluid outside the rock sample, and then obtain the migration and replacement of the fluid inside the rock sample at different time nodes, combine the T2-T1 threshold to distinguish the oil and water components, and quantify the remaining oil and intruded water content;

[0052] External oil content of rock sample during imbibition stage F 油外 Calculated by the following formula:

[0053] F 油外 =A 油占比 × (I 总 / I o ) (5)

[0054] Where F 油外 is the external oil content of the rock sample, A 油占比 is the oil phase peak area ratio, I 总 is the total mixed signal intensity; I o is the signal intensity per unit volume of the oil phase.

[0055] In some embodiments, in step S1, the rock sample is cut and polished into a standard plunger sample and dried to constant weight. After cooling, a T2-T1 two-dimensional spectrum test is performed to obtain a T2-T1 two-dimensional spectrum of the dried rock sample. The solid organic matter signal is deducted to determine the porosity benchmark (φ 干 ) is used as a normalized reference for subsequent calculation of the saturated oil phase volume to determine the rock sample volume (V 岩 ); the saturated rock sample is prepared by the following steps: placing the dried rock sample in a vacuum pressurization saturation device, first evacuating to absolute pressure to remove residual gas in the pores; then pressurizing to a set pressure and maintaining constant pressure; then monitoring the reading of the pressure gauge, and pressurizing and saturating for more than one week to fully saturate the rock sample with fluid; in step S1 or S2, the rock sample is a core, and the core is a standard core plunger sample used in the laboratory.

[0056] In order to make the purpose, technical solutions and advantages of the present invention more clearly understood, the present invention will be further described in detail below with reference to the accompanying drawings and embodiments. It should be understood that the specific embodiments described herein are only used to explain the present invention and are not intended to limit the present invention.

[0057] In the present invention, references to “some embodiments”, “this embodiment”, examples, etc. describe a subset of all possible embodiments, but it can be understood that “some embodiments” may be the same subset or different subsets of all possible embodiments, and may be combined with each other without conflict.

[0058] If similar descriptions of "first / second" appear in the application documents, the following explanation is added. In the following description, the terms "first\second\third" are merely used to distinguish similar objects and do not represent a specific order of the objects. It can be understood that "first\second\third" can be interchanged with the specific order or sequence where permitted, so that the embodiments described herein can be implemented in an order other than that illustrated or described herein.

[0059] In this embodiment, the term "and / or" is merely a description of the association relationship between associated objects, indicating that three relationships may exist. For example, object A and / or object B may represent three situations: object A exists alone, object A and object B exist at the same time, and object B exists alone.

[0060] Below, the embodiment of the present application is described. The embodiment described below is exemplary and is only used to explain the present application, and is not to be construed as limiting the present application. Where specific techniques or conditions are not specified in the embodiments, the techniques or conditions described in the literature in this area or the product specifications are used. Reagents or instruments used that do not specify the manufacturer are conventional products that can be obtained commercially.

[0061] The imbibition device in the following embodiment is combined with Figure 1 , including an imbibition container 1, in which a saturated rock sample 2 and an imbibition solution 3 are placed. In the initial stage of imbibition, the imbibition solution 3 is simulated formation water. As the imbibition experiment begins, the oil in the saturated rock sample 2 enters the simulated formation water.

[0062] Example 1

[0063] Combine Figure 1-3 This embodiment provides a method for continuous monitoring of fluid during rock sample imbibition, comprising the following steps:

[0064] 1) Rock sample pretreatment and drying rock sample benchmark test

[0065] A representative rock sample was extracted from the oil and gas reservoir. It was cut and polished into a standard plunger sample with a diameter of 25±0.5 mm and a length of 40±1 mm using a diamond cutting machine and sandpaper. It was then placed in a constant temperature oven and dried at 105°C to a constant weight (the difference between two consecutive weighings was less than 0.1%, and the water content of the rock sample was less than 0.05%). After cooling, it was wrapped with plastic wrap and polytetrafluoroethylene and subjected to T2-T1 two-dimensional spectrum testing to obtain the T2-T1 two-dimensional spectrum of the dried rock sample. The solid organic matter signal was subtracted to determine the porosity benchmark of the dry rock sample (φ 干 ) and volume (V 岩 The NMR instrument used was a MesoMR23-060H-I model from Suzhou Newmai Analytical Instrument Co., Ltd., equipped with a T2-T1 two-dimensional pulse sequence. n-Dodecane was used as the oil phase; its distribution and characteristics within the rock sample pores are representative of the oil phase in oil and gas reservoirs, providing accurate initial data for subsequent experiments.

[0066] In step 1), the rock sample is cut and polished into a standard plunger sample and dried to constant weight. After cooling, a T2-T1 two-dimensional spectrum test is performed to obtain the T2-T1 two-dimensional spectrum of the dried rock sample. The solid organic matter signal is deducted to determine the porosity benchmark of the dry rock sample (φ 干 ) is used as a normalized reference for subsequent calculation of the saturated oil phase volume to determine the rock sample volume (V 岩 The rock sample was prepared as a standard plunger sample with a diameter of 25±0.5mm and a length of 40±1mm to ensure that the size was suitable for the sensitive detection area of the nuclear magnetic resonance instrument. The drying was carried out at 105°C until the difference between two consecutive weighings was less than 0.1% to ensure that the rock sample was completely dry and to remove moisture and volatile substances, providing a dry and pure initial state for subsequent saturated oil operations and nuclear magnetic resonance testing. After cooling, the rock sample was wrapped with plastic wrap and polytetrafluoroethylene to prevent it from absorbing moisture or other impurities in the air again, thereby ensuring the accuracy and repeatability of the experiment.

[0067] 2) Oil-saturated rock samples and initial fluid data collection

[0068] Place the dried rock sample in a vacuum pressurizing device and evacuate to an absolute pressure of <10 -2 Pa to remove the residual gas in the pores, and then pressurize to 20MPa and maintain constant pressure for 7 days to make the rock sample fully saturated with the target oil phase n-dodecane, weigh the saturated oil rock sample weight, and the oil phase volume (V 油初 ) is obtained from (1). The T2-T1 two-dimensional spectrum test is performed on the oil-saturated rock sample. The original signal is converted into a T2-T1 two-dimensional distribution spectrum through the inversion algorithm. The T2-T1 two-dimensional spectrum is double-integrated to calculate the total porosity (φ 总 ), the calculation formula is obtained from (2), set the T1 / T2 threshold (such as oil phase T1 / T2≈5) to divide the fluid region, and calculate the initial saturation of the oil phase (S油初 ) and initial content (F 油初 ).

[0069] V 油初 = (W 饱和油 -W 干岩 ) / ρ 油 (1)

[0070] Where V 油初 is the volume of the oil phase in the saturated oil sample, W 饱和油 is the weight of the oil-saturated rock sample, W 干岩 is the weight of the oven-dried rock sample, ρ 油 is the density of oil;

[0071] (2)

[0072] Where φ 总 is the total porosity of the core sample, T1 and T2 are the longitudinal relaxation time and transverse relaxation time respectively, P(T2, T1) is the two-dimensional distribution function of T2-T1, which represents the joint probability density of relaxation time, dT1 and dT2 are the small changes of T1 and T2, Integrate the corresponding variable from 0 to positive infinity;

[0073] S 油初 = φ 油 / φ 总 (3)

[0074] Where S 油初 is the initial saturation of the oil phase, φ 油 is the porosity of the oil phase, φ 总 is the total porosity of the core sample;

[0075] F 油初 = S 油初 ×φ 总 ×V 岩 (4)

[0076] Where F 油初 is the initial content of oil phase in the core, S 油初 is the initial saturation of the oil phase, φ 总 is the total porosity of the core sample; V 岩 is the volume of the core sample;

[0077] In step 2), the dry rock sample is placed in a vacuum pressurizing device, and after vacuuming, pressurizing is performed to fully saturate the rock sample with the target oil phase. The saturated oil rock sample is weighed and the oil phase volume (V oil initial ) is calculated. Then, the saturated oil rock sample is subjected to a T2-T1 two-dimensional spectrum test to calculate the initial oil phase saturation (S oil initial ) and initial content (F oil initial ). The rock sample is vacuumed to an absolute pressure of <10 -2Pa to remove residual gas in the pores, and then pressurize to 20 MPa and maintain constant pressure for 7 days to fully saturate the rock sample with the target oil phase, ensure that the oil phase completely fills the pores of the rock sample, simulate the saturated oil state of the underground oil reservoir, and convert the original signal into a T2-T1 two-dimensional distribution map through the inversion algorithm. The T2-T1 two-dimensional spectrum is double-integrated to calculate the total porosity, and the T2-T1 threshold is set to divide the fluid area, providing accurate initial oil phase data for subsequent imbibition experiments and fluid change monitoring.

[0078] 3) Free fluid benchmark data collection

[0079] Pure n-dodecane is tested for T2-T1 2D spectra, and the characteristic peak positions (T2≈1000ms, T1≈5000ms, T1 / T2=5) are recorded to establish a 2D NMR identification benchmark for the free oil phase. Simulated formation water matching the salinity of the target reservoir is prepared and tested for T2-T1 2D spectra. The characteristic peak positions (T2≈2000ms, T1≈4000ms, T1 / T2=2) are recorded to establish a 2D NMR identification benchmark for the water phase. Both tests are conducted at a temperature of 25±0.5°C. These benchmark data allow accurate differentiation of signals from different fluids within the rock sample, providing a basis for subsequent quantitative fluid analysis.

[0080] In step 3), pure n-dodecane and the prepared simulated formation water are separately tested for T2-T1 2D spectra. The characteristic peak positions are recorded to establish a 2D NMR identification benchmark for the free oil and water phases. The T2-T1 2D spectra of the free oil phase and the simulated formation water are also recorded. These peak positions serve as a benchmark for subsequent identification of the oil and water phases, accurately distinguishing the signals of different fluids during the imbibition process and improving the accuracy of fluid quantitative analysis. The simulated formation water used must be compatible with the mineral composition of the rock sample to prevent dissolution or precipitation reactions from affecting the imbibition process.

[0081] 4) Continuous imbibition experiment and dynamic monitoring

[0082] Combine Figure 1 , the oil-saturated core was placed in an imbibition container 1 filled with simulated formation water (imbibition solution 3) for imbibition, ensuring that the rock sample was completely immersed and did not touch the container wall to avoid boundary effects interfering with the nuclear magnetic signal. At any time point after the imbibition began, the imbibition container was directly placed in a low-field nuclear magnetic resonance instrument (magnetic field strength 0.5T, frequency 21MHz) equipped with a T2-T1 two-dimensional pulse sequence to perform a T2-T1 two-dimensional spectrum test, obtain the two-dimensional spectrum of this stage, perform inversion processing on the measured spectrum, and calculate the total porosity (φ) corresponding to the total fluid signal inside the core. 总), and the signal intensity of the mixed fluid outside the core (including oil and water phases, without phase differentiation). By continuously monitoring the changes in fluid signals at different time points, the migration and replacement of fluids within the rock sample during the imbibition process can be dynamically tracked.

[0083] In step 4), the oil-saturated rock sample is placed in an imbibition container filled with simulated formation water, ensuring that the rock sample is completely immersed and does not touch the container wall. At any time point after the imbibition begins, the imbibition container is directly placed in the nuclear magnetic resonance instrument probe to perform a T2-T1 two-dimensional spectrum test, obtain the two-dimensional spectrum of this stage, and calculate the total porosity (φ) corresponding to the total fluid signal inside the core 总 ) and the signal intensity of the mixed fluid outside the core; the imbibition container has an inner diameter of 30 mm and a height of 50 mm, ensuring a sample-to-solution volume ratio of approximately 1:2. This design prevents contact between the sample and the container wall, reducing the impact of boundary effects on the NMR signal. It also ensures sufficient simulated formation water contacts the sample during the imbibition process, promoting the progress of the imbibition process. The NMR instrument is a low-field NMR instrument (magnetic field strength 0.5 T, frequency 21 MHz) equipped with a T2-T1 two-dimensional pulse sequence. This two-dimensional pulse sequence can obtain richer fluid information and improve the ability to monitor fluid changes. In addition, the NMR instrument must be equipped with a constant temperature control system (25±0.5°C) to prevent the impact of temperature fluctuations on relaxation time.

[0084] 5) Difference calculation and fluid component quantification

[0085] The total fluid content inside the core during the imbibition stage is calculated as F 总 =φ 总 ×V 岩 (The total fluid saturation inside the core is 1); Based on the intensity of the characteristic peak of the free oil phase, the proportion of the oil phase signal stripped from the mixed signal outside the core is calculated by the peak area ratio to obtain the oil content F outside the core 油外 , and its calculation formula is shown in (5), where the signal intensity per unit volume of the oil phase is I o It can be determined based on the free oil phase test results; the residual oil content is calculated as F 油剩余 =F 油初 -F 油外 ; The intrusion water content is calculated as F 水侵 =F 总 -F 油剩余 , and combined with the T1 / T2 threshold (water phase T1 / T2 ≈ 2) to verify the water phase signal region, ensuring that the calculated results are consistent with the two-dimensional spectrum characteristics. This difference calculation method can effectively remove background interference and improve the accuracy of quantitative analysis of fluid content, thereby enabling precise monitoring and quantitative analysis of fluid changes within rock samples during the imbibition process.

[0086] F 油外 =A油占比 × (I 总 / I o ) (5)

[0087] Where F 油外 is the oil content outside the core, A 油占比 is the oil phase peak area ratio, I 总 is the total mixed signal intensity; I o is the signal intensity per unit volume of the oil phase.

[0088] In step 5), the difference between the measured value and the initial value is calculated, and the oil and water components are distinguished by combining the T2-T1 threshold to quantify the remaining oil and intruded water content; the total fluid content inside the core during the imbibition stage is calculated as F 总 =φ 总 ×V 岩 According to the free oil phase characteristic peak intensity, the oil phase signal ratio is stripped from the core external mixed signal to obtain the core external oil content (F 油外 ), the remaining oil content is calculated as F 油剩 =F 油初 -F 油外 , the intrusion water content is calculated as F 水侵 =F 总 -F 油剩 , and combined with the T2-T1 threshold to verify the water phase signal area to ensure that the calculation results are consistent with the two-dimensional map characteristics. This difference calculation method can effectively remove background interference and improve the accuracy of quantitative analysis of fluid content.

[0089] This invention uses two-dimensional nuclear magnetic resonance technology (T2-T1) in conjunction with imbibition experiments to achieve continuous monitoring and quantitative analysis of fluid changes within the core. Its innovations include:

[0090] 1) The first application of two-dimensional nuclear magnetic resonance (T2-T1) technology to the non-interrupted continuous monitoring of core imbibition experiments. By directly acquiring the T2-T1 two-dimensional spectrum of the core in the imbibition container, the capillary pressure imbalance caused by experimental interruptions was avoided.

[0091] 2) A fluid signal separation method based on T1 / T2 threshold segmentation, combined with the characteristic peak benchmarks of the free oil and water phases, accurately distinguishes the oil and water components inside and outside the core;

[0092] Difference calculation and mass conservation are combined to quantify the 油剩 =F 油初 -F 油外 With F 水侵 =F 总 -F 油剩 Formula is used to realize dynamic tracking of fluid migration during imbibition.

[0093] The specific embodiments of the present invention described above do not limit the scope of protection of the present invention. Any other corresponding changes and modifications made based on the technical concept of the present invention should be included in the scope of protection of the claims of the present invention.

Claims

1. A method for continuous monitoring of fluid during rock sample imbibition, characterized in that: The following steps are involved: S1. Use nuclear magnetic resonance technology to test the T2-T1 spectra of saturated rock samples and oil samples in saturated rock samples; use nuclear magnetic resonance technology to test the T2-T1 spectrum of free oil phase and the T2-T1 spectrum of simulated formation water; S2. Place the saturated rock sample in an imbibition container filled with simulated formation water for imbibition, and perform T2-T1 spectrum nuclear magnetic resonance testing to calculate the total porosity φ corresponding to the total fluid signal inside the rock sample. 总 The signal intensity of the mixed fluid outside the rock sample is combined with the T2-T1 threshold to distinguish the oil and water components and quantify the remaining oil and intruded water content.

2. The method for continuous monitoring of fluid during rock sample imbibition according to claim 1, characterized in that: In step S1, the oil-saturated rock sample is tested for T2-T1 two-dimensional spectrum. The original signal is converted into T2-T1 two-dimensional distribution spectrum through the inversion algorithm. The total porosity (φ 总 ), the calculation formula is obtained from (2): （2） Where φ 总 is the total porosity of the rock sample, T1 and T2 are the longitudinal relaxation time and transverse relaxation time respectively, P(T2, T1) is the two-dimensional distribution function of T2-T1, which represents the joint probability density of relaxation time, dT1 and dT2 are the small changes of T1 and T2, Integrate the corresponding variable from 0 to positive infinity.

3. The method for continuous monitoring of fluid during rock sample imbibition according to claim 2, characterized in that: In step S1, the initial saturation S of the oil sample of the saturated rock sample 油初 and initial content F 油初 They are calculated by the following formulas: S 油初 = φ 油 / f 总 (3) F 油初 = S 油初 ×φ 总 ×V 岩 (4) Where S 油初 is the initial saturation of the oil phase, φ 油 is the porosity of the oil phase, φ 总 is the total porosity of the rock sample; where F 油初 is the initial content of oil phase in the rock sample, S 油初 is the initial saturation of the oil phase, φ 总 is the total porosity of the rock sample; V 岩 is the volume of the rock sample.

4. The method for continuous monitoring of fluid during rock sample imbibition according to claim 3, characterized in that: In step S2, the external oil content F of the rock sample during the imbibition stage is 油外 Calculated by the following formula: F 油外 =A 油占比 ×(I 总 / I o ) (5) Where F 油外 is the external oil content of the rock sample, A 油占比 is the oil phase peak area ratio, I 总 is the total mixed signal intensity; I o is the signal intensity per unit volume of the oil phase.

5. The method for continuous monitoring of fluid during rock sample imbibition according to claim 1, characterized in that: In step S1, the oil phase is n-dodecane.

6. The method for continuous monitoring of fluid during rock sample imbibition according to claim 1, characterized in that: In step S1, the volume of the oil sample saturating the rock sample is calculated using the following formula: V 油初 = (W 饱和油 -IN 干岩 ) / ρ 油 (1) Where V 油初 is the volume of the oil phase in the saturated oil sample, W 饱和油 is the weight of the oil-saturated rock sample, W 干岩 is the weight of the oven-dried rock sample, ρ 油 is the density of oil.

7. The method for continuous monitoring of fluid during rock sample imbibition according to claim 1, characterized in that: In step S1, the initial oil content of the saturated rock sample is calculated by the following formula: S 油初 = φ 油 / f 总 (3) Where S 油初 is the initial saturation of the oil phase, φ 油 is the porosity of the oil phase, φ 总 is the total porosity of the rock sample; F 油初 = S 油初 ×φ 总 ×V 岩 (4) Where F 油初 is the initial content of oil phase in the rock sample, S 油初 is the initial saturation of the oil phase, φ 总 is the total porosity of the rock sample; V 岩 is the volume of the rock sample.

8. The method for continuous monitoring of fluid during rock sample imbibition according to claim 1, characterized in that: In step S2, the remaining oil content is calculated as F 油剩余 =F 油初 -F 油外 Among them, F 油初 is the initial content of oil phase in the rock sample, F 油外 is the external oil content of the rock sample, and the intrusion water content is calculated as F 水侵 =F 总 -F 油剩 , where F 总 It is the total fluid content inside the rock sample during the imbibition stage, and is combined with the T1 / T2 threshold to verify the water phase signal area.

9. The method for continuous monitoring of fluid during rock sample imbibition according to claim 1, characterized in that: In step S1, the saturated rock sample is prepared by the following steps: placing the dried rock sample in a vacuum pressurization saturation device, first evacuating to absolute pressure to remove residual gas in the pores; then pressurizing to a set pressure and maintaining constant pressure; then monitoring the reading of the pressure gauge, and pressurizing and saturating for more than one week to ensure that the rock sample is fully saturated with fluid.

10. The method for continuous monitoring of fluid during rock sample imbibition according to claim 1, characterized in that: In step S1 or S2, the rock sample is a rock core, which is a standard rock core plug sample used in a laboratory.

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