A method and device for measuring solid phase deposition of crude oil under high temperature and high pressure conditions

Abstract

The application provides a method and device for measuring solid phase deposition amount of crude oil under high temperature and high pressure conditions, and relates to the technical field of oil and gas field development.The ground degassed crude oil, associated gas and field solid phase deposition sample are mixed and anti-soluble to prepare a formation crude oil sample which can truly reflect the formation crude oil component under the reservoir temperature and pressure of a target oil reservoir; then, the pressure is stepped down to a target pressure point under constant temperature, and a deposition monitoring area is demarcated; the spectral image data of the area are acquired, the spectral reflection reference rate is analyzed and calculated pixel by pixel, and a spectral distribution matrix is constructed; whether the solid phase deposition reaches equilibrium is determined by calculating the spatial consistency index and time convergence index of the matrix; finally, the solid phase deposition amount is calculated after the deposition reaches equilibrium; the application solves the problem of measurement distortion of the solid phase deposition amount under the condition of super-high pressure reservoir, and realizes non-interference, real-time monitoring and quantitative analysis of the deposition process.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field development technology, specifically to a method and apparatus for measuring the amount of crude oil solid phase deposition under high temperature and high pressure conditions. Background Technology

[0002] During the exploitation of deep, high-temperature, and ultra-high-pressure oil reservoirs, solid components such as asphaltene in crude oil are prone to deposition due to changes in temperature and pressure, clogging the wellbore and reservoir and severely affecting the recovery rate. Therefore, accurately measuring the amount of solid deposition in crude oil under formation conditions is crucial for developing effective exploitation and prevention strategies.

[0003] In existing technologies, the measurement of solid phase deposition is mostly based on atmospheric or low-to-medium pressure conditions. For example, Chinese invention patent application publication number CN114019148 A discloses a method for determining asphaltene deposition based on carbon dioxide huff and puff. This method obtains the formation parameters of the target reservoir and prepares rock samples; saturates the rock samples with oil and measures the original asphalt content of the oil samples; conducts carbon dioxide displacement experiments on the oil-saturated rock samples under different pressure differentials, temperatures, and displacement rates, collects and calculates the mass of the displaced fluid; determines the asphaltene content in the displaced oil samples; and calculates the amount of asphaltene deposition in the oil-saturated rock samples based on the original asphalt content of the oil samples and the asphaltene content in the displaced oil samples. The pressure source depends on advection pumps and hand-cranked pumps.

[0004] In industry, conventional core displacement experimental devices, such as systems using advection pumps and hand-cranked pumps, typically operate at pressures between 0 and 100 MPa. This fails to simulate the actual environment of high-pressure oil reservoirs, resulting in measurement conditions that do not match real formation conditions and distorted measurement results. Secondly, the formation crude oil (oil sample) prepared based on existing standard methods does not consider the back-dissolution effect of sedimentary solids. This leads to a lower content of heavy components (C7+) in the prepared crude oil sample, resulting in subsequent sedimentation measurements that are significantly lower than the actual values, thus affecting the measurement results.

[0005] 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

[0006] The purpose of this invention is to provide a method and apparatus for measuring the amount of solid phase deposition in crude oil under high temperature and high pressure conditions, so as to solve the problems mentioned in the background art.

[0007] To achieve the above objectives, the present invention provides the following technical solution:

[0008] A method for measuring the amount of solid phase deposition in crude oil under high temperature and high pressure conditions, comprising the following steps:

[0009] S1: Under the reservoir temperature and reservoir pressure of the target oil reservoir, the surface degassed crude oil, associated gas and solid sediment samples obtained from the field are mixed, and the solid sediments are reverse dissolved under the set temperature and pressure conditions to prepare a formation crude oil sample.

[0010] S2: At a constant storage temperature, the pressure of the environment where the formation crude oil sample is located is reduced from the reservoir pressure to the target pressure point, and then maintained at a constant pressure at the target pressure point. The area above the formation crude oil sample is used as a reference to delineate the sedimentation monitoring area.

[0011] S3: Acquire spectral image data of the sedimentation monitoring area, perform pixel-by-pixel analysis on the acquired spectral image data, extract the spectral response data of the pixels based on the preset feature bands, and calculate the spectral reflectance reference rate of each pixel.

[0012] S4: Based on the spectral reflectance reference rate, construct the spectral distribution matrix of the deposition monitoring area at the current moment, and further calculate the spatial consistency index and temporal convergence index of the matrix. When both the spatial consistency index and the temporal convergence index of the spectral distribution matrix converge, it is determined that the solid phase deposition in the crude oil has reached equilibrium.

[0013] S5: At a constant reservoir temperature, once it is determined that solid phase deposition has reached equilibrium, the crude oil sample is subjected to online pressure filtration to retain the precipitated solid phase deposits through the filter membrane; the mass difference of the filter membrane before and after filtration and the volume of the filtered crude oil are weighed to calculate the amount of solid phase deposition at the target pressure point.

[0014] In a preferred embodiment, when the solid sediment is reverse dissolved under set temperature and pressure conditions, the set temperature and pressure conditions are the reservoir temperature and reservoir pressure of the target oil reservoir; the surface degassed crude oil, associated gas and solid sediment samples obtained from the production site are mixed in a set ratio to obtain a mixed sample to be treated; the mixed sample to be treated is placed in a sealed container and the temperature and pressure are adjusted to the set temperature and pressure conditions.

[0015] Under the same conditions, the intensity signals of laser light passing through the mixed sample to be processed are obtained at several points. The standard deviation of the intensity signals at several points is calculated. When the standard deviation meets the preset threshold, it is determined that the solid sediment has reached equilibrium and the formation crude oil sample is obtained.

[0016] In a preferred embodiment, the process of reducing the pressure from the reservoir pressure to the target pressure point adopts a step-down depressurization method, specifically as follows:

[0017] Determine the pressure difference between the target pressure point and the reservoir pressure; based on the pressure difference, set several intermediate pressure points at equal pressure intervals within the range between the target pressure point and the reservoir pressure; lower the formation crude oil sample from the reservoir pressure sequentially from high to low to the intermediate pressure points until the target pressure point is reached; when the sample is lowered to the intermediate pressure point, maintain constant pressure for a set time, and then continue to lower it to the next intermediate pressure point.

[0018] In a preferred embodiment, the specific method for delineating the area as the sedimentation monitoring area is as follows: starting from the liquid surface, a rectangular area with a height of 1 / 4 of the total liquid surface height and a width consistent with the viewing window width is delineated as the sedimentation monitoring area.

[0019] In a preferred embodiment, the spectral image data is the reflectance of the spectrum in the wavelength range of 900nm to 1700nm, and the method for extracting the spectral response data of the pixels is as follows:

[0020] Select a preset feature band, construct a wavelength window with the feature band as the center, and calculate the average reflectance within the wavelength window corresponding to each feature band as the spectral response data of each pixel.

[0021] The preset characteristic bands include 1150nm, 1390nm and 1690nm. The wavelength window length at the 1150nm band is 10nm, the wavelength window length at the 1390nm band is 20nm, and the wavelength window length at the 1690nm band is 20nm.

[0022] In a preferred embodiment, step S3, the method for extracting the spectral response data of pixels and calculating the spectral reflectance reference rate of each pixel, includes:

[0023] I

[0024] in, I This indicates that the coordinates in the spectral image are... The reflectance reference rate of the pixel, This represents the average reflectance of the pixel at a wavelength of 1150nm. This represents the average reflectance of the pixel at a wavelength of 1390nm. This represents the average reflectance of the pixel at a wavelength of 1690nm.

[0025] , , The pre-set weighting coefficients, and satisfy the following conditions: + =1.

[0026] In a preferred embodiment, the logic for calculating the spatial consistency index is as follows: based on all element values ​​in the spectral distribution matrix at the current time, calculate the standard deviation of all elements in the matrix; when the standard deviation is less than a preset first threshold, determine that the spatial consistency index has converged.

[0027] In a preferred embodiment, the logic for calculating the time convergence metric is as follows:

[0028] Based on the current time, a reference time is determined by tracing back a set time length. At the reference time, spectral image data of the sedimentation monitoring area is collected, and step S3 is executed to obtain the spectral reflectance reference rate at the reference time.

[0029] Based on the aforementioned spectral reflectance reference rate, construct the spectral distribution matrix at the reference time;

[0030] The absolute difference matrix between the spectral distribution matrix at the current time and the spectral distribution matrix at the reference time is calculated element by element, and the average value of all elements of the absolute difference matrix is ​​obtained. When the average value is less than a preset second threshold, the time convergence index is determined to have converged.

[0031] The present invention also provides a measuring device for the amount of crude oil solid phase deposition under high temperature and high pressure conditions, for performing one of the above-mentioned measurement methods, comprising:

[0032] The sample construction module is used to mix surface degassed crude oil, associated gas, and solid sediment samples obtained from the field under the reservoir temperature and reservoir pressure of the target oil reservoir, so that the solid sediments are reverse dissolved under the set temperature and pressure conditions to prepare a formation crude oil sample.

[0033] The pressure adjustment module is used to reduce the pressure of the environment where the formation crude oil sample is located from the reservoir pressure to the target pressure point at a constant storage temperature, and maintain the constant pressure at the target pressure point. The area above the formation crude oil sample is used as a reference to delineate the sedimentation monitoring area.

[0034] The spectral acquisition module is used to acquire spectral image data of the sediment monitoring area, analyze the acquired spectral image data pixel by pixel, extract the spectral response data of the pixels based on preset feature bands, and calculate the spectral reflectance reference rate of each pixel.

[0035] The equilibrium determination module is used to construct the spectral distribution matrix of the deposition monitoring area at the current time based on the spectral reflectance reference rate, and further calculate the spatial consistency index and temporal convergence index of the matrix. When both the spatial consistency index and the temporal convergence index of the spectral distribution matrix converge, it is determined that the solid phase deposition in the crude oil has reached equilibrium.

[0036] The sedimentation measurement module is used to perform online pressure filtration on crude oil samples at a constant reservoir temperature after determining that solid phase deposition has reached equilibrium. The solid phase deposits precipitated are retained through a filter membrane. The difference in mass of the filter membrane before and after filtration is weighed along with the volume of the filtered crude oil to calculate the amount of solid phase deposition at the target pressure point.

[0037] Compared with the prior art, the beneficial effects of the present invention are:

[0038] This invention ensures the consistency of composition between experimental oil samples and formation crude oil by blending on-site solid sediments and formation crude oil from the source, solving the fundamental problem of low content of heavy components in conventional blending methods. It adopts multi-band near-infrared spectroscopy for non-contact, full-field, real-time monitoring and innovatively introduces two indicators, spatial consistency and temporal convergence, to quantitatively determine sedimentation equilibrium, avoiding subjective errors of manual observation and time lag of single-point sampling. By simulating the real production process through stepped pressure reduction and combining high-pressure visualization and online pressure-holding filtration technology, it achieves high-precision, dynamic measurement of the entire solid sedimentation process under simulated ultra-high pressure reservoir conditions. Attached Figure Description

[0039] Figure 1 This is a schematic diagram of the overall method flow of the present invention;

[0040] Figure 2 This is a graph showing the evolution of deposition amount over time in an embodiment of the present invention;

[0041] Figure 3 This is a structural block diagram of the device of the present invention. Detailed Implementation

[0042] To make the objectives, technical solutions, and advantages of this invention clearer, the invention will be further described in detail below with reference to specific embodiments.

[0043] It should be noted that, unless otherwise defined, the technical or scientific terms used in this invention should have the ordinary meaning understood by one of ordinary skill in the art to which this invention pertains. The terms "first," "second," and similar terms used in this invention do not indicate any order, quantity, or importance, but are merely used to distinguish different components. Terms such as "comprising" or "including" mean that the element or object preceding the word encompasses the elements or objects listed following the word and their equivalents, without excluding other elements or objects. Terms such as "connected" or "linked" are not limited to physical or mechanical connections, but can include electrical connections, whether direct or indirect. Terms such as "upper," "lower," "left," and "right" are used only to indicate relative positional relationships; when the absolute position of the described object changes, the relative positional relationship may also change accordingly.

[0044] Example:

[0045] Please see Figure 1 The present invention provides a technical solution:

[0046] A method for measuring the amount of solid phase deposition in crude oil under high temperature and high pressure conditions, comprising the following steps:

[0047] Step 1: Under the reservoir temperature and pressure of the target oil reservoir, the degassed crude oil, associated gas, and solid sediment samples obtained from the field are mixed. The solid sediments are then allowed to dissolve under the set temperature and pressure conditions to prepare a formation crude oil sample. Specifically, the purpose of adding the solid sediment sample is to realistically reproduce the potential ability of formation crude oil to precipitate solid phases under laboratory conditions. The addition ratio is usually estimated by referring to the asphaltene content analysis of the target oil reservoir or the field scaling history. The empirical range for the specific addition amount is 0.5% of the mass of the degassed crude oil.

[0048] When the solid sediments are reverse-dissolved under set temperature and pressure conditions, the set temperature and pressure conditions are the reservoir temperature and reservoir pressure of the target oil reservoir; specifically, they can be set in a high and low temperature test chamber for easy adjustment of the experimental pressure; the surface degassed crude oil, associated gas, and solid sediment samples obtained from the production site are mixed in a set ratio to obtain a mixed sample to be treated. The mixed sample to be treated is placed in a sealed container, such as a sample mixing device, and the stirring device of the sample mixing device is turned on to promote full contact and mixing of oil, gas and solids, and accelerate the realization of the dissolution equilibrium process. Under the same conditions, the intensity signals of laser light passing through the mixed sample to be treated are obtained at several points, and the standard deviation of the intensity signals at several points is calculated. When the standard deviation meets the preset threshold, if it is lower than 0.5% for several consecutive times, it is determined that the solid sediments have reached equilibrium and the formation crude oil sample is obtained.

[0049] By "redissolving" real sediments collected on-site under reservoir temperature and pressure conditions and recombining them into a system composed of crude oil and associated gas, the heavy components that have been precipitated during the production process are essentially returned to the experimental oil sample. At the same time, the mixing homogeneity is monitored by laser transmission method to ensure complete redissolution. By restoring the components at the source, the inherent defects of conventional preparation methods are made up for, so that all subsequent measurements are based on a sample that can truly reflect the potential sedimentary capacity of the formation crude oil.

[0050] In this embodiment, the same batch of degassed crude oil (100g) and associated gas (at a gas-oil ratio of 32m³ / t) were taken and divided into two groups:

[0051] Control group (no solid phase added): crude oil + associated gas only, stirred at 140 MPa and 135°C for 2 hours under constant temperature and pressure.

[0052] Experimental group (with solid phase): Crude oil + associated gas + 1.0g of solid sediment scraped from the wellbore, stirred for 2 hours under the same conditions. After equilibration, rapid online pressure filtration was performed, the residual solid phase on the filter membrane was collected and weighed, and the reversion rate was calculated. The resulting data table is as follows:

[0053] Verification table of anti-dissolution phenomenon

[0054]

[0055] As shown in the table above, the control group showed no solid precipitation throughout the process, eliminating interference from crude oil precipitation under reservoir conditions. The experimental group initially added 1000 mg of solid phase, and after equilibrium, only 693 mg remained, with approximately 307 mg being "redissolved" back into the liquid phase. This demonstrates that under real reservoir temperature and pressure, some solid phase can redissolve, and the system tends towards thermodynamic equilibrium. The experiment shows that when the amount of solid phase added is around 0.3% of the mass of degassed crude oil, complete redissolution can be achieved. The present invention preferably adds 0.5%, so that the system is in a slightly supersaturated solid phase equilibrium state, which more realistically simulates the thermodynamic state of solid-liquid coexistence in the original formation fluid, and is beneficial to the accurate characterization of solid phase precipitation behavior during subsequent depressurization.

[0056] In some embodiments, the set temperature and pressure conditions refer to the reservoir temperature and pressure of the target oil reservoir. For example, for an ultra-high pressure oil reservoir with a reservoir temperature of 135°C and a pressure of 140 MPa, the re-dissolution process is carried out in a closed environment at 135°C and 140 MPa. Laser homogeneity detection is performed using fiber optic probes integrated on both sides of the viewing window of the sealed container. One probe is connected to a laser source, emitting a laser beam of a specific wavelength that horizontally penetrates the mixed sample to be processed. The other probe is connected to a spectrometer or light intensity detector to receive the transmitted light signal. To ensure the homogeneity of the sample bulk phase, laser scanning detection is performed sequentially at different preset spatial locations. The standard deviation of the intensity signals at all detection points is calculated. When this standard deviation is lower than a preset threshold multiple times (e.g., three times consecutively), the sample is determined to have reached an optically homogeneous state, i.e., the solid phase sediments have dissolved and dispersed to equilibrium.

[0057] Step 2: Under constant storage temperature, reduce the pressure of the environment where the formation crude oil sample is located from the reservoir pressure to the target pressure point, and maintain constant pressure at the target pressure point. Use the liquid level above the formation crude oil sample as a reference to delineate an area as the sedimentation monitoring area.

[0058] During oil and gas extraction, formation pressure does not drop abruptly but decreases gradually and slowly with production. Therefore, the process of reducing pressure from reservoir pressure to the target pressure point employs a step-down pressure reduction method. The specific logic is as follows: determine the pressure difference between the target pressure point and the reservoir pressure; based on this pressure difference, set several intermediate pressure points at equal pressure intervals within the range between the target and reservoir pressures; gradually reduce the formation crude oil sample from high to low reservoir pressure to these intermediate pressure points until the target pressure point is reached. At each intermediate pressure point, maintain constant pressure for a set time before continuing to reduce to the next intermediate pressure point. The precipitation, growth, and aggregation of solid sediments is a time-dependent kinetic process; if the pressure drops abruptly, the system will deviate from equilibrium, and the deposition process may not be fully completed. Maintaining constant pressure at each intermediate pressure point provides the necessary relaxation time for the system to reach thermodynamic equilibrium, thus ensuring that the measured deposition amount at each pressure point is stable and accurate.

[0059] The depressurization process simulates the pressure drop caused by reservoir exploitation. By using a step-by-step depressurization method rather than an instantaneous one, the dynamic processes of pressure transmission and solid phase analysis in the formation are more realistically reproduced, avoiding the interference of pressure shocks on sediment morphology and rate. At the same time, the monitoring area is limited to a rectangular region near the liquid surface because, under the influence of gravity, precipitated solid particles tend to be suspended or initially aggregated in this area. The step-by-step depressurization strategy and the selection of the focused monitoring area work together. The smooth depressurization process allows sediments to be uniformly generated and changed within the monitoring area, while focused monitoring amplifies the effective signal in this area. Together, they provide a stable observation scenario for subsequent quantitative analysis based on the full-field spectrum.

[0060] In some embodiments, the pressure difference is 60 MPa when the reservoir pressure drops from 140 MPa to the target pressure point of 80 MPa. If the constant pressure interval is set to 15 MPa, the intermediate pressure points are successively 125 MPa, 110 MPa, and 95 MPa. The constant pressure is maintained at each intermediate pressure point for 30 minutes to 2 hours.

[0061] The following is a data table comparing the experimental and control groups when the reservoir pressure was reduced from 140 MPa to the target pressure point of 80 MPa at 135°C. The experimental group adopted a step-by-step pressure reduction, with intermediate pressure points of 125 MPa, 110 MPa, and 95 MPa, and the constant pressure was maintained for 60 minutes. The control group adopted a direct pressure reduction to 80 MPa.

[0062] Table 1 Comparison of the effects of stepped depressurization and direct depressurization on solid phase deposition behavior

[0063]

[0064] Table 2. Sedimentation evolution data over time.

[0065]

[0066] like Figure 2 As shown in Tables 1 and 2, although the total time of step depressurization is relatively long, the deposition process is controllable, the results are stable, and the physical significance is clear; it more realistically reflects the gradual precipitation behavior under formation conditions.

[0067] Direct depressurization causes a sharp increase in supersaturation due to drastic thermodynamic disturbances, leading to rapid non-equilibrium precipitation, resulting in high deposition rates and poor repeatability.

[0068] The specific method for delineating the area as the sedimentation monitoring area is as follows: Starting from the liquid surface, a rectangular area with a height of 1 / 4 of the total liquid surface height and a width consistent with the viewing window width is delineated as the sedimentation monitoring area. Solid sediments (such as bituminous materials and paraffin wax) typically have a higher density than crude oil, and under gravity, the precipitated solid particles will gradually settle. Delineating a rectangular area with a height of 1 / 4 of the total liquid surface height from the liquid surface is to focus on the initial precipitation area of ​​sediments, which can most sensitively reflect the beginning and changes in sedimentation. Limiting the width of the monitoring area to the same as the viewing window width can eliminate interference from container wall effects, ensuring that the collected spectral signals mainly come from the sedimentation process within the crude oil itself, improving the signal-to-noise ratio and comparability of the data. A fixed, standardized monitoring area allows for accurate spatiotemporal comparison of data collected at different pressure points and time points, which is a prerequisite for subsequent calculation of the "temporal convergence index" and "spatial consistency index" to determine equilibrium.

[0069] Step 3: Acquire spectral image data of the sedimentation monitoring area, perform pixel-by-pixel analysis on the acquired spectral image data, extract the spectral response data of the pixels based on the preset feature bands, and calculate the spectral reflectance reference rate of each pixel.

[0070] The above spectral image data represents the reflectance of the near-infrared spectrum in the wavelength range of 900 nm to 1700 nm. The method for extracting the spectral response data of the pixels is as follows:

[0071] Select a preset feature band, construct a wavelength window with the feature band as the center, and calculate the average reflectance within the wavelength window corresponding to each feature band as the spectral response data of each pixel.

[0072] The preset characteristic bands include 1150nm, 1390nm and 1690nm, with a wavelength window length of 10nm at the 1150nm band, 20nm at the 1390nm band and 20nm at the 1690nm band.

[0073] The 1145nm-1155nm band is sensitive to the second-order overtone vibrations of the CH bonds in hydrocarbons and is commonly used to detect saturated hydrocarbon components in crude oil. Solid-phase deposition alters the overall component ratio of crude oil, thus affecting the spectral response in this band.

[0074] The 1380nm-1400nm band is located near the absorption characteristic valley of water, which helps to monitor possible trace water interference in the experimental system. At the same time, this region also responds to the combination frequency vibrations of some organic molecules and can be used as an auxiliary judgment band.

[0075] The 1680nm-1700nm band represents an important diagnostic absorption region for hydrocarbons. Hydrocarbons exhibit absorption peaks near 1.72-1.73μm (i.e., 1720-1730nm), a key indicator for hydrocarbon identification. Selecting the edge band (1680-1700nm) effectively correlates this characteristic while potentially avoiding signal saturation issues caused by the strongest absorption peak, making it more suitable for monitoring reflectivity changes.

[0076] The formula for extracting the spectral response data of pixels and calculating the spectral reflectance reference rate of each pixel is as follows:

[0077] I

[0078] in, I This indicates that the coordinates in the spectral image are... The spectral reflectance reference rate of the pixel, This represents the spectral response data of the pixel at a wavelength of 1150nm; This represents the spectral response data of the pixel at a wavelength of 1390nm; This represents the spectral response data of the pixel at a wavelength of 1690nm;

[0079] , , The pre-set weighting coefficients, and satisfy the following conditions: + =1; In this embodiment, the 1690nm band is the most sensitive diagnostic band for sediments, therefore it has the largest weight. The 1390nm band is only used to exclude moisture interference, so it has the smallest weight. The 1150nm band can provide an important baseline reference. Based on the results of the sensitivity analysis, with the goal of improving the signal-to-noise ratio and sensitivity of the sediment monitoring signal, a multiple linear regression method is used to fit and optimize the weights. Finally, the weight coefficients are determined to be... =0.2、 =0.1、 =0.7.

[0080] Step 4: Based on the spectral reflectance reference rate, construct the spectral distribution matrix of the deposition monitoring area at the current moment, and further calculate the spatial consistency index and temporal convergence index of the matrix. When both the spatial consistency index and the temporal convergence index of the spectral distribution matrix converge, it is determined that the solid phase deposition in the crude oil has reached equilibrium.

[0081] The logic for calculating the spatial consistency index is as follows: based on all element values ​​in the spectral distribution matrix at the current time, calculate the standard deviation of all elements in the matrix. When the standard deviation is less than a preset first threshold, it is determined that the spatial consistency index has converged.

[0082] Each pixel within the sedimentation monitoring area calculated in step 3 Spectral reflectance reference rate I The pixels are arranged according to their spatial position in the two-dimensional image, forming an M-row, N-column matrix S, where M and N are the number of rows and columns of the monitored area pixels, respectively. The mathematical expression of this matrix is ​​as follows:

[0083]

[0084] This matrix visually reflects the spatial distribution of sediments within the monitoring area. When solid sediments are uniformly deposited, the element values ​​within the matrix tend to be consistent; when the sediment distribution is uneven or not yet stable, the element values ​​within the matrix will show significant differences.

[0085] The aforementioned spatial consistency index is used to quantify the uniformity of sediment distribution in space at the current moment; the formula is as follows:

[0086] =

[0087] The spatial consistency index is T, where T is the total number of pixels within the deposition monitoring area, i.e., T=M. N, Let be the spectral reflectance reference value of the k-th pixel, and u be the average spectral reflectance reference value of all N pixels; when If the value is less than the preset first threshold, the spatial consistency index is considered to have converged.

[0088] The logic for calculating the time convergence metric is as follows:

[0089] The reference time is determined by tracing back the current time by a set time length. At the reference time, spectral image data of the sedimentation monitoring area is collected. The spectral image data of the sedimentation monitoring area is obtained. The spectral image data is analyzed pixel by pixel, and the spectral response data of the pixel is extracted based on the preset feature bands to obtain the spectral reflectance reference rate at the reference time.

[0090] Based on the aforementioned spectral reflectance reference rate, construct the spectral distribution matrix at the reference time;

[0091] The absolute difference matrix between the spectral distribution matrix at the current time and the spectral distribution matrix at the reference time is calculated element by element, and the average value of all elements of the absolute difference matrix is ​​obtained. When the average value is less than a preset second threshold, the time convergence index is determined to have converged.

[0092] The formula for calculating the time convergence metric is as follows:

[0093] =

[0094] in, For time convergence metrics, The current time at the pixel level Spectral distribution matrix, The time length set for tracing back is at the pixel level. spectral distribution matrix;

[0095] Time convergence index Used to quantify the stability of deposition states over time, when The value is less than the preset second threshold, indicating that the time convergence index has converged. This means that within the time window, the average change in the spectral characteristics (i.e., depositional state) of the depositional area is negligible, and the equilibrium condition is met in the time dimension.

[0096] In some embodiments, the spatial consistency index reflects the uniformity of the spatial distribution of sediments. Its convergence means that the sediments have been uniformly dispersed or settled stably without violent convection. The temporal convergence index reflects the rate of change of the sedimentary state over time. Its convergence means that the spectral signal no longer changes significantly and the sedimentation process has reached dynamic equilibrium.

[0097] Near-infrared multi-band fusion weighted calculation provides a comprehensive optical index that is sensitive to and stable for sediments; while the criteria of spatial consistency and temporal convergence are mutually verified and indispensable. Spatial consistency alone may only be instantaneous uniformity, and temporal convergence alone may still be locally changing.

[0098] Only when both indicators converge can it be statistically proven that the sedimentary system has reached a stable dynamic equilibrium state across the entire region. This determination method completely eliminates the arbitrariness of subjective human judgment and the one-sidedness of single-point sampling.

[0099] Step 5: Under constant reservoir temperature, once solid-phase deposition is determined to have reached equilibrium, the crude oil sample is subjected to online pressure filtration. The precipitated solid-phase deposits are retained by the filter membrane. The mass difference of the filter membrane before and after filtration is weighed along with the volume of the filtered crude oil to calculate the amount of solid-phase deposition at the target pressure point. Pressure filtration prevents the redissolution of deposits and increases the accuracy of the experiment.

[0100] The process is completed under constant temperature and pressure, ensuring that the filtered material is the total amount of solid deposits in the pressure equilibrium state. Online operation avoids pressure and temperature changes and deposit loss caused by sample transfer. In this structure, the filtration operation is performed based on the determined equilibrium moment, ensuring that the measured amount is the final amount of deposits after stabilization, rather than the instantaneous value during a certain dynamic process. This makes the measurement results have clear physical meaning and high repeatability. Spectral dynamic monitoring and online pressure-holding filtration constitute a complete, closed-loop measurement and verification system.

[0101] In some embodiments, the online pressure-holding filtration device is connected to the visual reactor via a high-pressure pipeline. Before filtration, the system pressure is precisely stabilized at the target pressure point using a back pressure valve and a micro pump.

[0102] In this embodiment, a high-fidelity experimental sample with a chemical composition highly consistent with that of the formation crude oil was prepared using a reverse dissolution and compounding technique. The sample was then placed in a visualization high-pressure device that could simulate reservoir temperature and pressure. The extraction process was simulated by step-by-step depressurization to induce solid phase deposition. During this process, a full-field, continuous scan of the preset deposition monitoring area was performed using multi-band near-infrared spectroscopy.

[0103] By processing spectral data in real time, a spectral matrix reflecting the distribution of sediments is constructed, and its spatial uniformity and temporal stability are calculated. When both indicators reach the preset convergence criteria, the sedimentation is determined to have reached dynamic equilibrium. Under the condition of keeping the current temperature and pressure constant, the online filtration device is activated to intercept and weigh the solid phase sediments, thereby calculating the accurate and reliable amount of solid phase sediments at that pressure point.

[0104] Therefore, this embodiment solves the problem of inaccurate and unrepresentative measurement results caused by insufficient pressure simulation, sample distortion and balance misjudgment in the prior art by organically combining high-fidelity sample preparation, full-process intelligent spectral monitoring and dual-index quantitative balance determination, and realizes reliable measurement of crude oil solid phase deposition, especially under ultra-high pressure and harsh conditions.

[0105] The above formulas are all dimensionless calculations. The formulas are derived from software simulations based on a large amount of collected data to obtain the most recent real-world results. The preset parameters in the formulas are set by those skilled in the art according to the actual situation.

[0106] like Figure 3 As shown, the present invention also provides a measuring device for the amount of crude oil solid deposition under high temperature and high pressure conditions, used to perform the above-mentioned measurement method, comprising:

[0107] The sample construction module is used to mix surface degassed crude oil, associated gas, and solid sediment samples obtained from the field under the reservoir temperature and reservoir pressure of the target oil reservoir, so that the solid sediments are reverse dissolved under the set temperature and pressure conditions to prepare a formation crude oil sample.

[0108] The pressure adjustment module is used to reduce the pressure of the environment where the formation crude oil sample is located from the reservoir pressure to the target pressure point at a constant storage temperature, and maintain the constant pressure at the target pressure point. The area above the formation crude oil sample is used as a reference to delineate the sedimentation monitoring area.

[0109] The spectral acquisition module is used to acquire spectral image data of the sediment monitoring area, analyze the acquired spectral image data pixel by pixel, extract the spectral response data of the pixels based on preset feature bands, and calculate the spectral reflectance reference rate of each pixel.

[0110] The equilibrium determination module is used to construct the spectral distribution matrix of the deposition monitoring area at the current time based on the spectral reflectance reference rate, and further calculate the spatial consistency index and temporal convergence index of the matrix. When both the spatial consistency index and the temporal convergence index of the spectral distribution matrix converge, it is determined that the solid phase deposition in the crude oil has reached equilibrium.

[0111] The sedimentation measurement module is used to perform online pressure filtration on crude oil samples at a constant reservoir temperature after determining that solid phase deposition has reached equilibrium. The solid phase deposits precipitated are retained through a filter membrane. The difference in mass of the filter membrane before and after filtration is weighed along with the volume of the filtered crude oil to calculate the amount of solid phase deposition at the target pressure point.

[0112] The above embodiments can be implemented, in whole or in part, by software, hardware, firmware, or any other combination thereof. When implemented in software, the above embodiments can be implemented, in whole or in part, as a computer program product. Those skilled in the art will recognize that the units and algorithm steps of the various examples described in conjunction with the embodiments disclosed herein can be implemented by electronic hardware, or a combination of computer software and electronic hardware. Whether these functions are implemented in hardware or software depends on the specific application and design constraints of the technical solution.

[0113] The units described as separate components may or may not be physically separate. The components shown as units may or may not be physical units; they may be located in one place or distributed across multiple network units. Some or all of the units can be selected to achieve the purpose of this embodiment, depending on actual needs.

[0114] The above description is merely a specific embodiment of this application, but the scope of protection of this application is not limited thereto. Any changes or substitutions that can be easily conceived by those skilled in the art within the scope of the technology disclosed in this application should be included within the scope of protection of this application.

Claims

1. A method for measuring the amount of solid phase deposition in crude oil under high temperature and high pressure conditions, characterized in that, The specific steps include: S1: Under the reservoir temperature and reservoir pressure of the target oil reservoir, the surface degassed crude oil, associated gas and solid sediment samples obtained from the field are mixed, and the solid sediments are reverse dissolved under the set temperature and pressure conditions to prepare a formation crude oil sample. S2: At a constant storage temperature, the pressure of the environment where the formation crude oil sample is located is reduced from the reservoir pressure to the target pressure point, and then maintained at a constant pressure at the target pressure point. The area above the formation crude oil sample is used as a reference to delineate the sedimentation monitoring area. S3: Acquire spectral image data of the sedimentation monitoring area, perform pixel-by-pixel analysis on the acquired spectral image data, extract the spectral response data of the pixels based on the preset feature bands, and calculate the spectral reflectance reference rate of each pixel. S4: Based on the spectral reflectance reference rate, construct the spectral distribution matrix of the deposition monitoring area at the current moment, and further calculate the spatial consistency index and temporal convergence index of the matrix. When both the spatial consistency index and the temporal convergence index of the spectral distribution matrix converge, it is determined that the solid phase deposition in the crude oil has reached equilibrium. S5: At a constant reservoir temperature, once it is determined that solid phase deposition has reached equilibrium, the crude oil sample is subjected to online pressure filtration to retain the precipitated solid phase deposits through the filter membrane; the mass difference of the filter membrane before and after filtration and the volume of the filtered crude oil are weighed to calculate the amount of solid phase deposition at the target pressure point; The logic for calculating the spatial consistency index is as follows: based on all element values ​​in the spectral distribution matrix at the current time, calculate the standard deviation of all elements in the matrix. When the standard deviation is less than a preset first threshold, it is determined that the spatial consistency index has converged. The logic for calculating the time convergence metric is as follows: Based on the current time, a reference time is determined by tracing back a set time length. At the reference time, spectral image data of the sedimentation monitoring area is collected, and step S3 is executed to obtain the spectral reflectance reference rate at the reference time. Based on the aforementioned spectral reflectance reference rate, construct the spectral distribution matrix at the reference time; The absolute difference matrix between the spectral distribution matrix at the current time and the spectral distribution matrix at the reference time is calculated element by element, and the average value of all elements of the absolute difference matrix is ​​obtained. When the average value is less than a preset second threshold, the time convergence index is determined to have converged.

2. The measurement method according to claim 1, characterized in that: When the solid sediments are reverse dissolved under set temperature and pressure conditions, the set temperature and pressure conditions are the reservoir temperature and reservoir pressure of the target oil reservoir; the surface degassed crude oil, associated gas and solid sediment samples obtained from the production site are mixed in a set ratio to obtain a mixed sample to be treated; the mixed sample to be treated is placed in a sealed container and the temperature and pressure are adjusted to the set temperature and pressure conditions. Under the same conditions, the intensity signals of laser light passing through the mixed sample to be processed are obtained at several points. The standard deviation of the intensity signals at several points is calculated. When the standard deviation meets the preset threshold, it is determined that the solid sediment has reached equilibrium and the formation crude oil sample is obtained.

3. The measurement method according to claim 1, characterized in that: The process of reducing the pressure from the reservoir pressure to the target pressure point adopts a step-down depressurization method, specifically as follows: Determine the pressure difference between the target pressure point and the reservoir pressure; based on the pressure difference, set several intermediate pressure points at equal pressure intervals within the range between the target pressure point and the reservoir pressure; lower the formation crude oil sample from the reservoir pressure sequentially from high to low to the intermediate pressure points until the target pressure point is reached; when the sample is lowered to the intermediate pressure point, maintain constant pressure for a set time, and then continue to lower it to the next intermediate pressure point.

4. The measurement method according to claim 3, characterized in that: The specific method for delineating the area as the sedimentation monitoring area is as follows: taking the liquid surface as the starting point, delineate a rectangular area with a height of 1 / 4 of the total liquid surface height and a width consistent with the width of the viewing window as the sedimentation monitoring area.

5. The measurement method according to claim 4, characterized in that: The spectral image data is the reflectance of the spectrum in the wavelength range of 900nm to 1700nm. The method for extracting the spectral response data of the pixels is as follows: Select a preset feature band, construct a wavelength window with the feature band as the center, and calculate the average reflectance within the wavelength window corresponding to each feature band as the spectral response data of each pixel. The preset characteristic bands include 1150nm, 1390nm and 1690nm. The wavelength window length at the 1150nm band is 10nm, the wavelength window length at the 1390nm band is 20nm, and the wavelength window length at the 1690nm band is 20nm.

6. The measurement method according to claim 1, characterized in that: In step S3, the method for extracting the spectral response data of pixels and calculating the spectral reflectance reference rate of each pixel includes: I in, I This indicates that the coordinates in the spectral image are... The reflectance reference rate of the pixel, This represents the average reflectance of the pixel at a wavelength of 1150nm. This represents the average reflectance of the pixel at a wavelength of 1390nm. This represents the average reflectance of the pixel at a wavelength of 1690nm. , , The pre-set weighting coefficients, and satisfy the following conditions: + =1.

7. A measuring device for the amount of solid phase deposition in crude oil under high temperature and high pressure conditions, the measuring device being used to perform a measuring method according to any one of claims 1-6, characterized in that, include: The sample construction module is used to mix surface degassed crude oil, associated gas, and solid sediment samples obtained from the field under the reservoir temperature and reservoir pressure of the target oil reservoir, so that the solid sediments are reverse dissolved under the set temperature and pressure conditions to prepare a formation crude oil sample. The pressure adjustment module is used to reduce the pressure of the environment where the formation crude oil sample is located from the reservoir pressure to the target pressure point at a constant storage temperature, and maintain the constant pressure at the target pressure point. The area above the formation crude oil sample is used as a reference to delineate the sedimentation monitoring area. The spectral acquisition module is used to acquire spectral image data of the sediment monitoring area, analyze the acquired spectral image data pixel by pixel, extract the spectral response data of the pixels based on preset feature bands, and calculate the spectral reflectance reference rate of each pixel. The equilibrium determination module is used to construct the spectral distribution matrix of the deposition monitoring area at the current time based on the spectral reflectance reference rate, and further calculate the spatial consistency index and temporal convergence index of the matrix. When both the spatial consistency index and the temporal convergence index of the spectral distribution matrix converge, it is determined that the solid phase deposition in the crude oil has reached equilibrium. The sedimentation measurement module is used to perform online pressure filtration on crude oil samples at a constant reservoir temperature after determining that solid phase deposition has reached equilibrium. The solid phase deposits precipitated are retained through a filter membrane. The difference in mass of the filter membrane before and after filtration is weighed along with the volume of the filtered crude oil to calculate the amount of solid phase deposition at the target pressure point.

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