Nmr method for measuring solid phase deposit of crude oil in porous medium

Abstract

This invention discloses a nuclear magnetic resonance (NMR) method for measuring the solid phase deposition of crude oil in porous media, belonging to the field of oil and gas reservoir development technology. By using a single saturation of crude oil in a core sample and leveraging the characteristics of online NMR technology, the method employs a comparison of experimental and NMR measurements, along with a 1:1 standard line reference, to determine the standard echo interval T in the transverse relaxation time T2 measurement acquisition parameters. E This method directly measures the amount of solid phase deposition in pore fluids in situ, solving the technical problems of existing technologies that cannot maintain the original characteristics of the sample, effectively avoid the interference of solid skeleton response and solid phase deposition particles, and are difficult to measure the solid phase deposition content of active oil in situ. It achieves the technical effect of rapid, efficient and accurate measurement of the amount of crude oil solid phase precipitation in cores under specific temperature and pressure conditions. The method is reliable in principle, simple to operate and highly applicable, and the test results are accurate and reliable, making it more suitable for the fine characterization needs of complex oil and gas reservoirs.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas reservoir development technology, specifically relating to a nuclear magnetic resonance method for measuring the amount of crude oil solid phase deposition in porous media. Background Technology

[0002] Crude oil is a flowing or semi-flowing liquid, primarily composed of low-carbon light hydrocarbons, paraffin wax, gums, and asphaltenes. Under reservoir conditions, these components exist in phase equilibrium. However, as crude oil is extracted, reservoir conditions and its composition change, disrupting the initial phase equilibrium and making it susceptible to deposition of heavy components, such as asphalt and paraffin wax. This solid-phase deposition can clog reservoir pores and throats, weakening crude oil flow and reducing development efficiency.

[0003] Therefore, studying the deposition patterns of solid phases during crude oil extraction and analyzing the influence of factors such as temperature and pressure on solid phase deposition can promote the efficient development of oil and gas fields. Existing methods for measuring crude oil solid phase deposition include laser methods, ultrasonic methods, differential pressure methods, and thermal methods. With the development of nuclear magnetic resonance (NMR) technology, NMR measurement has achieved excellent results in evaluating the fluid properties of complex reservoirs such as tight sandstone and low-porosity, due to its superior ability to directly detect hydrogen nuclei in pore fluids, avoiding the influence of solid framework response and solid phase deposition particles.Patent (publication number CN107941838B) proposes a quantitative evaluation method for the influence of asphaltene precipitation on pore throat distribution during CO2 flooding by combining centrifugation with nuclear magnetic resonance (NMR) T2 spectroscopy. While this method can visually reveal the sizes of pore throats in which precipitation occurs and the extent of blockage, the centrifugation process may mechanically damage the fragile pore structure, and the offline NMR method may alter the depositional state of asphaltene, leading to inaccurate quantitative evaluation. In 2017, Chen Wang et al. used offline NMR technology to quantitatively reveal the damage mechanism of asphaltene precipitation on the permeability of low-permeability sandstone cores during CO2 flooding at the microscale and analyzed the asphaltene precipitation content in the produced oil. However, saturating the core with water before and after the displacement experiment and scanning the corresponding T2 spectra may alter the distribution and state of some precipitates, making the corresponding T2 spectra inaccurate and causing some errors (Wang, C (Wang, Chen), et al. Effect of asphaltene precipitation on CO2-flooding performance in Low-permeability sandstones: anuclear magnetic resonance study[J]. RSC Advances,2017,Vol.7(61): 38367-38376); In 2018, Chen Wang et al. used offline nuclear magnetic resonance technology to identify changes in pore distribution by the T2 spectrum of the saturated fluid before and after asphalt precipitation, and indirectly analyzed the amount of precipitation. However, during the secondary saturation and displacement process, existing precipitates may be displaced, causing errors. At the same time, the applicable temperature and pressure range of the experimental method is limited, and it fails to cover a wider range of reservoir conditions (Wang C, Li T, Gao H, et al. Quantitative study on the blockage degree of pores due to asphaltene precipitation in low-permeability reservoirs with NMR technique[J]. Journal of Petroleum Science and Engineering,2018,163703-711).

[0004] The invention patents (publication numbers CN107288615A, CN113075081A, CN207144926U, CN202610147424) all use the principle of measuring the laser transmittance of crude oil, plotting the laser transmittance value against the number of gas-oil contact times, and judging whether solid phase deposition occurs in crude oil after the number of gas-oil contact times by judging whether a clear inflection point appears, but they cannot quantitatively evaluate the amount of solid phase deposition. The invention patent (publication number CN202383131U) proposes a high-pressure simulation test instrument for crude oil asphaltenes deposition, which collects crude oil filtrate through a sampling tube and analyzes the oil sample to calculate the amount of asphaltenes deposition. Zhang Wei et al. proposed an ultrasonic method to qualitatively judge the solid phase deposition point in their article "Research on Ultrasonic Measurement of Solid Phase Deposition Point". CN107219322A proposes an experimental device for dynamically measuring the amount of asphaltenes precipitation generated by CO2-crude oil reaction, which uses image analysis software to measure the area and particle size distribution of asphaltenes precipitation, thereby obtaining the amount of precipitation. CN107209166A and the literature "Prediction of Asphaltenes Precipitation During CO2 Injection" use mathematical methods to predict the amount of asphaltenes precipitation. CN103308667A proposes a method for measuring the amount of asphaltenes precipitation in crude oil during carbon dioxide immiscible flooding in oil-bearing cores, which involves purifying asphaltenes from the reservoir fluid produced after displacement and calculating the asphaltenes content in the displacement products. Invention patent (publication number CN114166680A) calculates the amount of solid phase deposition in the crude oil at the measured temperature and pressure based on the change in the weight of the nanofiltration membrane before and after measurement.

[0005] However, the aforementioned traditional methods for measuring sediment volume—whether laser, ultrasonic, differential pressure, or thermal methods—all suffer from a series of problems: poor adaptability (e.g., laser methods are limited by crude oil color and are ineffective for black, heavy crude oil, and have large errors at high concentrations); and the thermal method is severely affected by environmental temperature fluctuations. There is also response lag (ultrasonic methods lack sensitivity in the early stages of wax crystal precipitation, while differential pressure methods require a large accumulation of solid phase to clog the filter membrane before signal capture, making accurate measurement of the sedimentation initiation point impossible). Furthermore, traditional methods are destructive, often involving offline testing, and cannot recreate the high-temperature, high-pressure environment of the formation. Finally, they provide limited information, only acquiring macroscopic temperature or pressure changes, failing to reveal microscopic sedimentation mechanisms. In contrast, nuclear magnetic resonance (NMR) technology is non-destructive to samples, offering more than 10 times the efficiency and approximately 14% higher accuracy per test compared to traditional methods. It is unaffected by crude oil color or conductivity, and can measure light, black, and heavy oils. Furthermore, imaging technology allows direct visualization of the distribution of wax crystals and bitumen in the pores. It can also simultaneously distinguish and detect the content of oil, water, and wax—achievements impossible with traditional methods. It is evident that laser, ultrasonic, differential pressure, and thermal methods, due to inherent defects such as optical interference, signal lag, or destructiveness, are no longer sufficient to meet the requirements for fine characterization of complex oil and gas reservoirs. Nuclear magnetic resonance (NMR) technology, with its comprehensive advantages of being non-destructive, accurate, visual, and multi-parameter, is gradually becoming the mainstream advanced method for measuring crude oil solid phase sedimentation.

[0006] The information disclosed in the background section is only intended to enhance the understanding of the background of this disclosure, and therefore may include information that does not constitute prior art known to those skilled in the art. Summary of the Invention

[0007] This invention provides a nuclear magnetic resonance (NMR) method for measuring the amount of crude oil solid phase deposition in porous media. By saturating the crude oil core once, and leveraging the characteristics of online NMR technology, the method compares experimental measurements with NMR values ​​and uses a 1:1 standard line reference to determine the standard echo interval TE in the transverse relaxation time T2 measurement parameters. This allows for direct in-situ measurement of the amount of solid phase deposition in the pore fluid. This method solves the technical problems of existing technologies, such as the inability to maintain the original characteristics of the sample, effectively avoiding interference from the solid skeleton response and solid phase deposition particles, and the difficulty in directly measuring the content of active oil solid phase deposition in situ. It achieves a rapid, efficient, and accurate measurement of the amount of crude oil solid phase precipitation in the core under specific temperature and pressure conditions. The method is reliable in principle, simple to operate, and highly applicable, providing accurate and reliable test results. It is well-suited for the fine characterization needs of complex oil and gas reservoirs and effectively overcomes the shortcomings of existing technologies.

[0008] To achieve the above technical objectives, the present invention adopts the following technical solution, including the following steps:

[0009] Step S1: Prepare a representative live oil with known components and gas-oil ratio as the calibration crude oil;

[0010] Step S2: Plot the calibration curve; place the prepared live oil in the glass tube of the PVT instrument under the set experimental conditions, change the temperature or pressure parameters that affect solid phase deposition, measure the volume of the live oil with separated solid phase, and calculate the solid phase percentage Q of the separated solid phase obtained in the first experiment. r1 Repeat this step continuously, changing only one parameter, temperature or pressure, and calculate the percentage of solid phase Q that has been separated. ri (i=2, 3, 4.....), until the experimental data is sufficient to plot the calibration curve, then plot the calibration curve;

[0011] Step S3: Draw Q r -Q t Relationship curve; core samples selected using live oil saturation, with an initial echo interval of T. E1 Measure the nuclear magnetic resonance T2 spectrum and calculate the area S1 enclosed by the T2 spectrum curve 1 and the horizontal axis. For the core sample saturated with active oil, only change the conditions consistent with those changed in step S2, and adjust the echo interval to T. E2 Measure the nuclear magnetic resonance T2 spectrum and calculate the area S2 enclosed by the T2 spectrum curve 2 and the horizontal axis. If the experimental data is insufficient to plot Q... r Measured solid percentage content and Q t The relationship curve of solid phase percentage obtained by NMR testing is obtained by adjusting the condition parameters to be the same as those adjusted in step S2, with the echo interval as T. E2 Measure the nuclear magnetic resonance T2 spectrum and calculate the area S enclosed by the T2 spectrum curve i and the horizontal axis. i (i=3, 4, 5…..), until the experimental data is sufficient to plot Q. r Measured solid percentage content and Q t After NMR analysis of the solid content percentage relationship curve, plot Qr-Q t Relationship curve;

[0012] Step S4: If Q r -Q t If the relationship curve 1 coincides with the 1:1 standard line, then the echo interval T E2 To calibrate the echo interval T E标定 Then the measurement of the solid content in the core can begin; if Q r -Q t If the deviation between the relationship curve 1 and the 1:1 standard line is large, then adjust the echo interval T. Ei+1 (i=2, 3, 4...), repeat step S3 until Q. r -Q t The relationship curve i (i=2, 3, 4…..) coincides with the 1:1 standard line, at which point the echo interval T Ei+1 To calibrate the echo interval T E标定 ;

[0013] Step S5: Plot the Q-∆S relationship curve; in the calibration section, calibrate the echo interval T. E标定 The corresponding data were processed to establish a quantitative relationship curve between the nuclear magnetic resonance signal difference ΔS and the solid content Q, which served as the basis for subsequent calculation of the solid sedimentation amount in the core.

[0014] Step S6: Referring to the PVT report of the target block, the composition and gas-oil ratio of the crude oil to be tested are known. Using the sample provided by the target block, a certain volume of live oil is prepared so that its key parameters fit the parameters in the PVT report.

[0015] Step S7: Saturate the selected core with live oil in one go, and record the volume V of live oil used for saturating the core to calibrate the echo interval T. E标定 Measure the nuclear magnetic resonance T2 spectrum and calculate the area S1 enclosed by the T2 spectrum curve 1 and the abscissa. Take a core sample that has been saturated with active oil and change only the conditions consistent with those in the calibration section to calibrate the echo interval T. E标定 Measure the nuclear magnetic resonance T2 spectrum and calculate the area S2 enclosed by the T2 spectrum curve 2 and the horizontal axis;

[0016] Step S8: Process the data from step S7: ΔS1 = (S1 - S2), find Q1 corresponding to ΔS1 in the Q-ΔS measurement relationship curve; V 固 =Q1×V, which gives the solid content V already deposited in the core under these conditions. 固 .

[0017] As a preferred embodiment of the nuclear magnetic resonance measurement method for crude oil solid phase deposition in porous media according to the present invention, the specific operation process of step S1 includes:

[0018] Step S1.1: Mix low-carbon light hydrocarbons (C1-C8) with asphalt in a certain volume ratio to prepare a certain volume of active oil.

[0019] Step S1.2: Compare and verify with the key parameters in the PVT report.

[0020] As a preferred embodiment of the nuclear magnetic resonance measurement method for crude oil solid phase deposition in porous media according to the present invention, the key parameters in step S1.2 include: bubble point pressure, formation volume factor, viscosity under formation pressure, and formation crude oil density.

[0021] As a preferred embodiment of the nuclear magnetic resonance measurement method for crude oil solid phase deposition in porous media according to the present invention, the specific operation process of step S2 includes:

[0022] Step S2.1: Place a portion of the volume of live oil into the glass tube of the PVT apparatus under the set experimental conditions to ensure that the live oil is in a single-phase state under the experimental conditions;

[0023] Step S2.2: Let it stand for a period of time to allow the active oil in the glass tube of the PVT instrument to stabilize;

[0024] Step S2.3: Change a certain condition that affects solid phase deposition by changing temperature or pressure, while keeping other conditions unchanged. Under this condition, ensure that the live oil is still in a single-phase state and let it stand for a period of time to allow the solid phase in the live oil to fully deposit.

[0025] Step S2.4: Separate the deposited solid phase from the live oil using filter paper, measure the volume of the separated solid phase in the live oil, and calculate the percentage of the separated solid phase Q. r1 Q r That is, the proportion of the separated solid phase volume to the initial volume of the live oil;

[0026] Step S2.5: Adjust the temperature or pressure parameters to ensure the live oil is in a single-phase state, and calculate the percentage of solid phase Q that has been separated. r2 ;

[0027] Step S2.6: If the experimental data is insufficient to plot the calibration curve, repeat step S2.5 until the experimental data is sufficient to plot the calibration curve;

[0028] Step S2.7: The percentage of solid phase Q in step S2 ri (i=1, 2, 3...) and the corresponding changing condition X are plotted as Q. r The -X relationship curve serves as the calibration relationship curve.

[0029] As a preferred embodiment of the nuclear magnetic resonance measurement method for crude oil solid phase deposition in porous media according to the present invention, the specific operation process of step S3 includes:

[0030] Step S3.1: Select artificially cemented sandstone cores with similar physical properties based on the reservoir properties of the target block;

[0031] Step S3.2: Take a sufficient amount of live oil, saturate the core with the live oil under the set experimental conditions, and record the volume of live oil used to saturate the core;

[0032] Step S3.3: The initial echo interval is T E1 The echo interval T E1 Generally, the size is small, so as to record the signal of active oil in the core, measure the nuclear magnetic resonance T2 spectrum, and calculate the area S1 enclosed by the T2 spectrum curve 1 and the horizontal axis.

[0033] Step S3.4: Take the core containing saturated active oil, change the conditions to be consistent with those in Step S2, let it stand for a period of time to allow the solid phase of the active oil in the core to fully settle, and adjust the echo interval to T. E2 The echo interval T E2 Generally, the signal is increased to ignore the signal of the solid phase already deposited in the core, the nuclear magnetic resonance T2 spectrum is measured, and the area S2 enclosed by the T2 spectrum curve 2 and the horizontal axis is calculated.

[0034] Step S3.5: If the experimental data is insufficient to plot Q r Measured solid percentage content and Q t The relationship curve between NMR and solid phase percentage was obtained by adjusting only the condition parameters to match those adjusted in step S2, with the echo interval as T. E2 Measure the nuclear magnetic resonance T2 spectrum and calculate the area S enclosed by the T2 spectrum curve i and the horizontal axis. i (i=3, 4, 5…..), until the experimental data is sufficient to plot Q. r -Q t Relationship curve;

[0035] Step S3.6: Process the data from step S3: Q t1 =(S1-S2) / S1、Q t2 =(S1-S3) / S1、Q t3 =(S1-S4) / S1、Q ti =(S1-S i+1 ) / S1 (i=4, 5, 6…..), and plot the processed data as Q. r Measured solid percentage content and Q t Curve showing the relationship between the percentage content of solid phase determined by NMR spectroscopy.

[0036] As a preferred embodiment of the nuclear magnetic resonance measurement method for crude oil solid phase deposition in porous media according to the present invention, the specific operation process of step S5 includes:

[0037] Step S5.1: Calculate the signal difference ΔS and match the corresponding solid content Qt; calibrate the echo interval T. E标定 The measured T2 spectral areas (S1, S2, S3, S4, S5...) will be used to calibrate the echo interval T. E标定 The corresponding numbers are processed as follows: ΔS1 = (S1 - S2), ΔS2 = (S1 - S3), ΔS3 = (S1 - S4), ΔS i =(S1-S i+1 (i=4, 5, 6…..), and its corresponding data is Q t1 Q t2 Q t3 Q ti(i=4, 5, 6...);

[0038] Step S5.2: Plot the Q-ΔS relationship curve; plot the data points (ΔS1, Qt1), (ΔS2, Qt2), (ΔS3, Qt3)... obtained in step S5.1 into a scatter plot with ΔS as the abscissa and Q as the ordinate, and perform linear or polynomial fitting to obtain the Q-ΔS measurement relationship curve, which will be used in the subsequent step S8 to find the corresponding solid percentage content Q based on the measured ΔS.

[0039] As a preferred embodiment of the nuclear magnetic resonance measurement method for crude oil solid phase deposition in porous media according to the present invention, the specific operation process of step S6 includes:

[0040] Step S6.1: Obtain crude oil samples from the target block and analyze key parameters; take representative downhole crude oil samples from the target block, and use a PVT analyzer to determine the dissolved gas-oil ratio (GOR), saturation pressure, volume factor, and crude oil composition under formation conditions, and record the benchmark parameters used for live oil preparation in the PVT report of the block.

[0041] Step S6.2: Calculate the required components and quantities; based on the gas-oil ratio and component data in the PVT report, use the equation of state to back-calculate the mass of degassed crude oil and the amount of natural gas required to prepare a certain volume of live oil; if the crude oil in the target block contains specific non-hydrocarbon gases, also include them proportionally to ensure that the calculation results make the deviation between the saturation pressure of the live oil at the set temperature and the original saturation pressure in the PVT report less than ±0.5%;

[0042] Step S6.3: Reconstitute and verify the live oil in a high-temperature and high-pressure PVT container; inject the calculated amount of degassed crude oil into a clean PVT cylinder, add the calculated amount of gas components according to the metering, and stir for no less than 4 hours under conditions of 3~5 MPa above saturation pressure and formation temperature ±1℃ to reach thermodynamic equilibrium; then verify that the relative error of the gas-oil ratio, saturation pressure and density of the reconstituted live oil with the parameters reported by PVT does not exceed ±2% through constant mass expansion or flash evaporation test; if it exceeds the standard, fine-tune the gas injection amount and reconstitute until the fitting requirements are met.

[0043] As a preferred embodiment of the nuclear magnetic resonance measurement method for crude oil solid phase deposition in porous media according to the present invention, the specific operation process of step S7 includes:

[0044] Step S7.1: Select artificially cemented sandstone cores with similar physical properties based on the reservoir properties of the target block;

[0045] Step S7.2: Take a sufficient amount of live oil, saturate the core with the live oil once under the set experimental conditions, and record the volume V of live oil used for the first saturation of the core.

[0046] Step S7.3: Using the calibration echo interval T E标定 Measure the nuclear magnetic resonance T2 spectrum and calculate the area S1 enclosed by the T2 spectrum curve 1 and the horizontal axis;

[0047] Step S7.4: Take a core sample containing once-saturated live oil, change the conditions to be consistent with those in the calibration section, and let it stand for a period of time to allow the solid phase of the live oil in the core sample to fully settle, in order to calibrate the echo interval T. E标定 Measure the nuclear magnetic resonance T2 spectrum and calculate the area S2 enclosed by the T2 spectrum curve 2 and the horizontal axis.

[0048] In summary, the present invention has at least one of the following beneficial technical effects:

[0049] First, this application utilizes online nuclear magnetic resonance (NMR) technology, which effectively avoids interference from solid framework response and solid-phase deposition particles, directly measuring the amount of solid-phase deposition in pore fluids. This avoids processing such as cutting or grinding, preserving the original characteristics of the sample and ensuring the accuracy of the measurement results. Second, this application is based on transverse relaxation time T2 measurement, combined with echo interval T... E This invention enables rapid and efficient measurement of solid phase deposition under specific temperature and pressure conditions, while eliminating human error and improving the real-time performance and accuracy of the experiment. Furthermore, the experimental method avoids secondary saturation, preventing changes in the deposits during the saturation process and further ensuring the reliability of the measurement results.

[0050] In summary, leveraging the advantages of online nuclear magnetic resonance (NMR) technology, the interference from solid framework response and solid-phase deposition particles can be effectively avoided, allowing direct measurement of solid-phase deposition in pore fluids without cutting or grinding, thus preserving the original characteristics of the sample to the greatest extent. This is based on the transverse relaxation time T2 and the echo interval T... E This invention utilizes specific characteristics to quickly, accurately, and in real-time measure solid phase deposition under certain temperature and pressure conditions, reducing human error and avoiding changes caused by secondary saturation. The invention is based on reliable principles, is easy to operate, and is applicable to the determination of solid phase deposition in crude oil under specific reservoir conditions and in different types of core samples, possessing broad market application prospects. Attached Figure Description

[0051] The accompanying drawings, which are incorporated in and form part of this specification, illustrate embodiments consistent with the invention and, together with the description, serve to explain the principles of the invention.

[0052] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, for those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0053] Figure 1 A flowchart of a nuclear magnetic resonance method for measuring the amount of crude oil solid phase deposition in porous media;

[0054] Figure 2 For calibration part of the flowchart;

[0055] Figure 3 solid percentage Q r Corresponding curve diagram showing the relationship between the X calibration condition and the X calibration condition;

[0056] Figure 4 Figure 1-5 shows the T2 spectrum curve for the first cycle.

[0057] Figure 5 The measured percentage of solid content Q r The percentage of solid phase content Q measured by NMR t Relationship curve 1;

[0058] Figure 6 Figure 1-5 shows the T2 spectrum curve for the second cycle;

[0059] Figure 7 The measured percentage of solid content Q r The percentage of solid phase content Q measured by NMR t Relationship curves in Figures 2 and 3;

[0060] Figure 8 The measurement diagrams are for the T2 spectrum curves 2 and 3.

[0061] Figure 9 The relationship curve and the plot of the points to be determined for Q-ΔS were calculated. Detailed Implementation

[0062] The accompanying drawings and descriptions provided herein may have been simplified to illustrate aspects relevant to a clear understanding of the apparatus, systems, and methods described herein, while other aspects that may be found in typical similar devices, systems, and methods have been omitted for clarity. Therefore, those skilled in the art will recognize that other elements and / or operations may be desired and / or necessary for implementing the devices, systems, and methods described herein. However, because such elements and operations are known in the art and do not contribute to a better understanding of this disclosure, a discussion of such elements and operations may not be provided herein for the sake of brevity. Nevertheless, this disclosure is still intended to include all such elements, variations, and modifications to the described aspects that are known to those skilled in the art.

[0063] Implementations are provided throughout this disclosure to make it thorough and fully convey the scope of the disclosed embodiments to those skilled in the art. Numerous specific details, such as embodiments of specific components, apparatuses, and methods, are set forth to provide a thorough understanding of implementations of this disclosure. However, it will be apparent to those skilled in the art that certain specific details disclosed are not required and that implementations may be carried out in different forms. Therefore, implementations should not be construed as limiting the scope of this disclosure. As mentioned above, in some implementations, well-known processes, well-known equipment structures, and well-known technologies may not be described in detail.

[0064] The terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting. For example, the singular forms “a” and “described” as used herein may also be intended to include the plural forms unless the context clearly indicates otherwise. The terms “comprising,” “including,” “containing,” and “having” are inclusive and thus specify the presence of the stated features, integers, steps, operations, elements, and / or components, but do not exclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and / or groups thereof. Unless specifically determined as a preferred or desired order of execution, the steps, processes, and operations described herein should not be construed as requiring them to be performed in the particular order discussed or shown. It should also be understood that additional or alternative steps may be employed in place of or in combination with the disclosed aspects.

[0065] The present invention will be further described below with reference to the accompanying drawings and examples to enable those skilled in the art to understand the invention. However, it should be understood that the present invention is not limited to the specific embodiments described herein. For those skilled in the art, any variations that fall within the spirit and scope of the invention as defined and determined by the appended claims are all within the scope of protection.

[0066] Implementation Cases

[0067] A nuclear magnetic resonance method for measuring the amount of crude oil solid phase deposition in porous media (see...) Figure 1 The process includes two parts: calibration and measurement, and involves the following steps:

[0068] I. Calibration (see process) Figure 2 )

[0069] Step S1: Prepare a representative crude oil with known components and gas-oil ratio as the crude oil used in the calibration section. The specific operation procedure is as follows:

[0070] Step S1.1: Mix low-carbon light hydrocarbons (C1~C8) with asphalt at a volume ratio of 4:1 to prepare 500ml of active oil;

[0071] Step S1.2: The prepared live oil should have key parameters, such as viscosity and density, that are close to those in the PVT report under reservoir conditions of 81.3℃ and 40.78MPa. The key parameters of the crude oil used for calibration are shown in Table 1.

[0072] Table 1 Key parameters of the crude oil used for calibration

[0073]

[0074] Step S2: Place 20ml of the prepared live oil into the glass cylinder of a PVT instrument at 70℃ and 39MPa. Reduce the pressure inside the glass cylinder of the PVT instrument to 34MPa, measure the volume of the live oil with separated solid phases, and calculate the percentage of solid phase Q. r1 =3.01%, repeat this step continuously, changing only the parameters of this condition, and calculate the percentage of solid phase Q that has been separated. ri (i=2, 3, 4…..), meaning the pressure drops to 29 MPa, Q r2 =5.031%, pressure dropped to 24MPa, Q r3 =8.503%, pressure dropped to 19 MPa, Q r3 =13.51%, the above data is plotted as a calibration relationship curve (see below). Figure 2 The specific operating procedure is as follows:

[0075] Step S2.1: Place 220ml of live oil into the glass cylinder of the PVT instrument at a temperature of 70℃ and a pressure of 39MPa;

[0076] Step S2.2: Let it stand for a period of time to allow the active oil in the glass tube of the PVT instrument to stabilize;

[0077] Step S2.3: Reduce the pressure inside the glass tube of the PVT instrument to 34 MPa and let it stand for a period of time to allow the solid phase in the active oil to fully deposit;

[0078] Step S2.4: Separate the deposited solid phase from the live oil using filter paper, measure the volume of the separated solid phase in the live oil, and calculate the percentage of the separated solid phase Q. r1 =3.01%;

[0079] Step S2.5: Reduce the pressure inside the glass tube of the PVT instrument to 29 MPa and calculate the percentage of the separated solid phase Q. r2 =5.031%;

[0080] Step S2.6: If the experimental data is insufficient to plot the calibration curve, repeat step S2.5 until the experimental data is sufficient to plot the calibration curve, i.e., when the pressure drops to 24 MPa, Q r3 =8.503%, pressure dropped to 19 MPa, Q r3 =13.51%;

[0081] Step S2.7: Plot the solid percentage content Qri (i=1, 2, 3…) from step S2 against the corresponding changing condition X to form a Qr-X relationship curve, which will serve as the calibration curve. See [link to relevant documentation]. Figure 3 .

[0082] Step S3: Using the core sample saturated with live oil, with an initial echo interval of T... E1 =0.2ms, the nuclear magnetic resonance T2 spectrum was measured, and the area enclosed by curve 1 and the abscissa, S1=28484.28, was calculated. The core sample containing saturated active oil was tested at 70℃ and 34MPa, with the echo interval adjusted to T. E2 =0.3ms, measure the T2 spectrum of nuclear magnetic resonance, and calculate the area S2 = 27797.80 enclosed by the T2 spectrum curve and the horizontal axis. If the experimental data is insufficient to plot Q r Measured solid percentage content and Q t The relationship curve between NMR and solid phase percentage is as follows: at a temperature of 70℃ and a pressure of 29MPa, T E2 =0.3ms, S3=27339.21; at a temperature of 70℃ and a pressure of 24MPa, T E2 =0.3ms, S4=26396.38; at a temperature of 70℃ and a pressure of 19MPa, T E2 =0.3ms, S5=24775.6, plot Q r Measured solid percentage content and Q t The relationship curve between NMR and solid phase percentage is shown in the figure. Figure 4 The specific operating procedure is as follows:

[0083] Step S3.1: Based on the reservoir physical properties of the target block, select an artificially cemented sandstone core with similar physical properties and a porosity of 16.21%;

[0084] Step S3.2: Take a sufficient amount of live oil and saturate the core with the live oil at a temperature of 70℃ and a pressure of 39MPa. Record the volume of live oil used to saturate the core as V=4.607ml.

[0085] Step S3.3: Initial echo interval T E1 =0.2ms, measure the nuclear magnetic resonance T2 spectrum, and calculate the area S1 = 28484.28 enclosed by the T2 spectrum curve 1 and the horizontal axis;

[0086] Step S3.4: The core sample containing saturated active oil is allowed to stand at 70℃ and 34MPa for a period of time to allow the solid phase of the active oil in the core to fully settle. The echo interval is then adjusted to T. E2=0.3ms, measure the nuclear magnetic resonance T2 spectrum, and calculate the area S2 = 27797.80 enclosed by the T2 spectrum curve 2 and the horizontal axis;

[0087] Step S3.5: If the experimental data is insufficient to plot Q r Measured solid percentage content and Q t The relationship curve between NMR and solid phase percentage is as follows: at a temperature of 70℃ and a pressure of 29MPa, T E2 =0.3ms, S3=27339.21; at a temperature of 70℃ and a pressure of 24MPa, T E2 =0.3ms, S4=26396.38; at a temperature of 70℃ and a pressure of 19MPa, T E2 =0.3ms, S5=24775.6, calibrate the first cycle T2 spectrum curve 1-5, see [reference]. Figure 4 ;

[0088] Step S3.6: Process the data from step S3: Q t1 =2.441%, Q t2 =4.02%, Q t3 =7.33%, Q t4 =13.02%, and the processed data is plotted as Q. r Measured solid percentage content and Q t Figure 2 shows the relationship between the percentage of solid phase content determined by NMR spectroscopy. Figure 5 .

[0089] Step S4: Discover Q r -Q t If the relationship curve 1 differs significantly from the 1:1 standard line and lies on the 1:1 standard line, then adjust the echo interval T. E3 =0.4ms, repeat steps S3.4, S3.5, and S3.6, then we have S1=28484.28, S2=27709.51, S3=27085.70, S4=26140.02, S5=24553.45. The T2 spectrum curve for the second cycle is calibrated as shown in 1-5. Figure 6 Data processing: Q t1 =2.72%, Q t2 =4.91%, Q t3 =8.23%, Q t4 =13.80%, plot the processed data as Q. r -Q t Relationship curve 2, see Figure 7 ; Discover Q r -Q t If the relationship curve 2 almost coincides with the 1:1 standard line, then the echo interval T at this time is... E3 To calibrate the echo interval TE标定 =0.4ms, and the measurement of the solid content of the core can begin.

[0090] II. Measurement

[0091] Step S5: In the calibration section, set the calibration echo interval T. E标定 The corresponding numbers are processed as follows: ΔS1=774.772, ΔS2=1398.578, ΔS3=2344.256, ΔS4=3930.831, and their corresponding data is Q. t1 =2.72%, Q t2 =4.91%, Q t3 =8.23%, Q t4 =13.80%, these data were plotted as a Q-ΔS relationship curve, which serves as the Q-ΔS measurement relationship curve. See [link to relevant documentation]. Figure 9 .

[0092] Step S6: Referring to the PVT report of the target block, the composition and gas-oil ratio of the crude oil to be tested are known (see Table 2). Using the sample provided by the target block, prepare 100 ml of live oil so that its key parameters at a temperature of 80.3℃ and a pressure of 39.11 MPa are close to the parameters in the PVT report (see Table 3).

[0093] Table 2 Experimental analysis data of well fluid composition

[0094]

[0095] Table 3 Key parameters of the crude oil used for determination

[0096]

[0097] Step S7: Saturate the selected core with a porosity of 16.13% using 20ml of live oil, and record the volume of live oil used for saturation as V=4.571ml, to calibrate the echo interval T. E标定 =0.4ms, the nuclear magnetic resonance T2 spectrum was measured, and the area S1 enclosed by the T2 spectrum curve and the abscissa was calculated as 27646.15. The core of saturated active oil was subjected to nuclear magnetic resonance at a temperature of 70℃ and a pressure of 29MPa, with a calibrated echo interval T. E标定 =0.4ms, measure the T2 spectrum of nuclear magnetic resonance, and calculate the area S2 = 26277.92 enclosed by the T2 spectrum curve and the horizontal axis. The specific operation procedure is as follows:

[0098] Step S7.1: Based on the reservoir physical properties of the target block, select an artificially cemented sandstone core with similar physical properties and a porosity of 16.13%;

[0099] Step S7.2: Take 20ml of live oil and saturate the core with the live oil at a temperature of 70℃ and a pressure of 39MPa. Record the volume of live oil used to saturate the core as V=4.571ml.

[0100] Step S7.3: Using the calibration echo interval T E标定 =0.4ms, measure the nuclear magnetic resonance T2 spectrum, and calculate the area S1 = 27646.15 enclosed by the T2 spectrum curve 1 and the horizontal axis;

[0101] Step S7.4: The core containing saturated active oil is left to stand at 70℃ and 29MPa for a period of time to allow the solid phase of the active oil in the core to fully settle, in order to calibrate the echo interval T. E标定 =0.4ms, measure the nuclear magnetic resonance T2 spectrum, and calculate the area S2 = 26277.92 enclosed by the T2 spectrum curve 2 and the horizontal axis.

[0102] Step S8: Process the data from step S7: ΔS1 = 1357.426, find Q1 = 4.751% corresponding to ΔS1 in the Q-ΔS measurement relationship curve; V 固 =0.217ml, yielding the solid content V of the sediment deposited in the core at 70℃ and 29MPa. 固 =0.217ml, see Figure 9 .

[0103] The above description is not intended to limit the form of the present invention. Although the present invention has been disclosed through the above embodiments, it is not intended to limit the present invention. Any person skilled in the art can make some changes or modifications to the above-disclosed technical content to create equivalent embodiments without departing from the scope of the technical solution of the present invention. Any simple modifications, equivalent changes and modifications made to the above embodiments based on the technical essence of the present invention without departing from the content of the technical solution of the present invention shall still fall within the scope of the technical solution of the present invention.

Claims

1. A nuclear magnetic resonance method for measuring the amount of crude oil solid phase deposition in porous media, characterized in that, Includes the following steps: Step S1: Prepare a representative live oil with known components and gas-oil ratio as the calibration crude oil; Step S2: Plotting calibration curve; put the prepared live oil into the PVT instrument glass cylinder under the set experimental conditions, change the temperature or pressure parameters affecting the solid phase deposition, measure the volume of the separated solid phase of the live oil and calculate the solid phase percentage Q of the separated solid phase obtained in the first experiment r1 This step is repeated continuously, only one of the temperature or pressure parameters is changed, and the solid phase percentage Q of the separated solid phase is calculated ri (i=2, 3, 4, …), until the experimental data are sufficient to plot the calibration curve; Step S3: Plot Q r Q t Relationship curve; core is saturated with live oil for the first time, with initial echo interval T E1 Area S1 is obtained by measuring T2 spectrum; then under the same condition change, with adjusted echo interval T E2 Area S2 is obtained by measuring T2 spectrum; if the data is insufficient, continue to change the condition, with adjusted echo interval T E2 Repeat to obtain Si (i=3, 4, 5…), until the data is sufficient, and plot the relationship curve of Qr and Qt; Step S4: If Q r -Q t The relationship curve 1 coincides with the 1:1 standard line, and the echo interval T E2 is the calibrated echo interval T E标定 , and the measurement of the core solid content can be started; if Q r -Q t The relationship curve 1 deviates greatly from the 1:1 standard line, and the echo interval T Ei+1 is adjusted, and step S3 is repeated until Q r -Q t The relationship curve i (i=2, 3, 4…) coincides with the 1:1 standard line, and the echo interval T Ei+1 is the calibrated echo interval T E标定 ; Step S5: draw the Q-ΔS relationship curve; in the calibration part, the calibration echo interval T E标定 The corresponding data is processed to establish the quantitative relationship curve between the nuclear magnetic signal difference ΔS and the solid phase percentage Q, which serves as the basis for subsequent core solid phase deposition amount calculation. Step S6: Referring to the PVT report of the target block, the composition and gas-oil ratio of the crude oil to be tested are known. Using the sample provided by the target block, a certain volume of live oil is prepared so that its key parameters fit the parameters in the PVT report. Step S7: saturate the selected core with live oil once, record the volume of live oil used to saturate the core, V, to calibrate the echo spacing, T E标定 , measure the NMR T2 spectrum, and calculate the area, S1, enclosed by the T2 spectrum curve 1 and the abscissa, and saturate the core with live oil once, changing only the conditions consistent with the changes in the calibration section to calibrate the echo spacing, T E标定 , measure the NMR T2 spectrum, and calculate the area, S2, enclosed by the T2 spectrum curve 2 and the abscissa; Step S8: Process the data from step S7: ΔS1 = (S1 - S2), find Q1 corresponding to ΔS1 in the Q-ΔS measurement relationship curve; V 固 =Q1×V, which gives the solid content V already deposited in the core under these conditions. 固 .

2. The nuclear magnetic resonance measurement method for crude oil solid phase deposition in porous media according to claim 1, characterized in that: The specific operation process of step S1 includes: Step S1.1: Mix low-carbon light hydrocarbons (C1-C8) with asphalt in a certain volume ratio to prepare a certain volume of active oil. Step S1.2: Compare and verify with the key parameters in the PVT report.

3. The nuclear magnetic resonance measurement method for crude oil solid phase deposition in porous media according to claim 2, characterized in that: The key parameters in step S1.2 include: bubble point pressure, formation volume factor, viscosity under formation pressure, and formation crude oil density.

4. The nuclear magnetic resonance measurement method for the amount of crude oil solid phase deposition in porous media according to claim 1, characterized in that: The specific operation process of step S2 includes: Step S2.1: Place a portion of the volume of live oil into the glass tube of the PVT apparatus under the set experimental conditions to ensure that the live oil is in a single-phase state under the experimental conditions; Step S2.2: Let it stand for a period of time to allow the active oil in the glass tube of the PVT instrument to stabilize; Step S2.3: Change a certain condition that affects solid phase deposition by changing temperature or pressure, while keeping other conditions unchanged. Under this condition, ensure that the live oil is still in a single-phase state and let it stand for a period of time to allow the solid phase in the live oil to fully deposit. Step S2.4: Separate the deposited solid phase from the live oil using filter paper, measure the volume of the separated solid phase in the live oil, and calculate the percentage of the separated solid phase Q. r1 Q r That is, the proportion of the separated solid phase volume to the initial volume of the live oil; Step S2.5: Adjust the temperature or pressure parameters to ensure the live oil is in a single-phase state, and calculate the percentage of solid phase Q that has been separated. r2 ; Step S2.6: If the experimental data is insufficient to plot the calibration curve, repeat step S2.5 until the experimental data is sufficient to plot the calibration curve; Step S2.7: The percentage of solid phase Q in step S2 ri (i=1, 2, 3...) and the corresponding changing condition X are plotted as Q. r The -X relationship curve serves as the calibration relationship curve.

5. The nuclear magnetic resonance measurement method for the amount of crude oil solid phase deposition in porous media according to claim 1, characterized in that: The specific operation process of step S3 includes: Step S3.1: Select artificially cemented sandstone cores with similar physical properties based on the reservoir properties of the target block; Step S3.2: Take a sufficient amount of live oil, saturate the core with the live oil under the set experimental conditions, and record the volume of live oil used to saturate the core; Step S3.3: The initial echo interval is T E1 Record the signal of active oil in the core, measure the nuclear magnetic resonance T2 spectrum, and calculate the area S1 enclosed by the T2 spectrum curve 1 and the horizontal axis. Step S3.4: Take the core containing saturated active oil, change the conditions to be consistent with those in Step S2, let it stand for a period of time to allow the solid phase of the active oil in the core to fully settle, and adjust the echo interval to T. E2 Measure the nuclear magnetic resonance T2 spectrum and calculate the area S2 enclosed by the T2 spectrum curve 2 and the horizontal axis; Step S3.5: If the experimental data is insufficient to plot Q r Measured solid percentage content and Q t The relationship curve between NMR and solid phase percentage was obtained by adjusting only the condition parameters to match those adjusted in step S2, with the echo interval as T. E2 Measure the nuclear magnetic resonance T2 spectrum and calculate the area S enclosed by the T2 spectrum curve i and the horizontal axis. i (i=3, 4, 5…..), until the experimental data is sufficient to plot Q. r -Q t Relationship curve; Step S3.6: Process the data from step S3: Q t1 =(S1-S2) / S1、Q t2 =(S1-S3) / S1、Q t3 =(S1-S4) / S1、Q ti =(S1-S i+1 ) / S1 (i=4, 5, 6…..), and plot the processed data as Q. r Measured solid percentage content and Q t Curve showing the relationship between the percentage content of solid phase determined by NMR spectroscopy.

6. The nuclear magnetic resonance method for measuring the amount of crude oil solid phase deposition in a porous medium according to claim 1, characterized in that: The specific operation process of step S5 includes: Step S5.1: Calculate the signal difference ΔS and match the corresponding solid content Qt; calibrate the echo interval T. E标定 The measured T2 spectral areas (S1, S2, S3, S4, S5...) will be used to calibrate the echo interval T. E标定 The corresponding numbers are processed as follows: ΔS1 = (S1 - S2), ΔS2 = (S1 - S3), ΔS3 = (S1 - S4), ΔS i =(S1-S i+1 (i=4, 5, 6…..), and its corresponding data is Q t1 Q t2 Q t3 Q ti (i=4, 5, 6...); Step S5.2: Plot the Q-ΔS relationship curve; with ΔS as the abscissa and Q as the ordinate, plot the data points (ΔS1,Qt1), (ΔS2,Qt2), (ΔS3,Qt3)... obtained in step S5.1 into a scatter plot, and perform linear or polynomial fitting to obtain the Q-ΔS measurement relationship curve.

7. The nuclear magnetic resonance measurement method for the amount of crude oil solid phase deposition in porous media according to claim 1, characterized in that: The specific operation process of step S6 includes: Step S6.1: Obtain crude oil samples from the target block and analyze key parameters; take representative downhole crude oil samples from the target block, and use a PVT analyzer to determine the dissolved gas-oil ratio (GOR), saturation pressure, volume factor, and crude oil composition under formation conditions, and record the benchmark parameters used for live oil preparation in the PVT report of the block. Step S6.2: Calculate the required components and quantities; based on the gas-oil ratio and component data in the PVT report, use the equation of state to back-calculate the mass of degassed crude oil and the amount of natural gas required to prepare a certain volume of live oil; if the crude oil in the target block contains specific non-hydrocarbon gases, also include them proportionally to ensure that the calculation results make the deviation between the saturation pressure of the live oil at the set temperature and the original saturation pressure in the PVT report less than ±0.5%; Step S6.3: Reconstitute and verify the live oil in a high-temperature and high-pressure PVT container; inject the calculated amount of degassed crude oil into a clean PVT cylinder, add the calculated amount of gas components according to the metering, and stir for no less than 4 hours under conditions of 3~5 MPa above saturation pressure and formation temperature ±1℃ to reach thermodynamic equilibrium; then verify that the relative error of the gas-oil ratio, saturation pressure and density of the reconstituted live oil with the parameters reported by PVT does not exceed ±2% through constant mass expansion or flash evaporation test; if it exceeds the standard, fine-tune the gas injection amount and reconstitute until the fitting requirements are met.

8. The nuclear magnetic resonance method for measuring the amount of crude oil solid phase deposition in a porous medium according to claim 1, characterized in that: The specific operation process of step S7 includes: Step S7.1: Select artificially cemented sandstone cores with similar physical properties based on the reservoir properties of the target block; Step S7.2: Take a sufficient amount of live oil, saturate the core with the live oil once under the set experimental conditions, and record the volume V of live oil used for the first saturation of the core. Step S7.3: Using the calibrated echo interval T E标定 Measure the nuclear magnetic resonance T2 spectrum and calculate the area S1 enclosed by the T2 spectrum curve 1 and the horizontal axis; Step S7.4: Take a core sample containing once-saturated live oil, change the conditions to be consistent with those in the calibration section, and let it stand for a period of time to allow the solid phase of the live oil in the core sample to fully settle, in order to calibrate the echo interval T. E标定 Measure the nuclear magnetic resonance T2 spectrum and calculate the area S2 enclosed by the T2 spectrum curve 2 and the horizontal axis.

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