A method and apparatus for determining the free oil content in shale samples

Abstract

This specification provides a method and apparatus for determining the free oil content of shale samples. The method involves acquiring shale samples from a target area and performing fluid storage state restoration processing to obtain the target shale sample. The target shale sample is then subjected to isothermal evaporation, during which sample mass data and NMR monitoring data are collected at multiple time points. A time-porosity curve is constructed based on the sample mass data and NMR monitoring data. The porosity interval corresponding to the free oil evaporation stage is determined based on the time-porosity curve. The first NMR monitoring data at the start time and the second NMR monitoring data at the end time are extracted from the NMR monitoring data at multiple time points, and the change in clay adsorbed water content is calculated. The free oil content of the target shale sample is determined based on the porosity interval and the change in clay adsorbed water content. This improves the accuracy and reliability of the free oil content determination results.

Description

Technical Field

[0001] This manual belongs to the field of shale oil exploration and development technology, and in particular relates to a method and apparatus for determining the free oil content of shale samples. Background Technology

[0002] Currently, the determination of free oil content mostly uses pyrolysis and Soxhlet extraction methods, and only uses the content of light hydrocarbons to replace the content of free oil, which has the problem of large measurement error.

[0003] There is currently no effective solution to the above problems. Summary of the Invention

[0004] This specification provides a method and apparatus for determining the free oil content in shale samples, which solves the problem that existing free oil content determination results have large deviations and are difficult to accurately reflect the actual fluid occurrence state in shale pores.

[0005] This specification provides a method for determining the free oil content in shale samples, including:

[0006] A shale sample from the target area is obtained, and the fluid occurrence state recovery process is performed on the shale sample to obtain the target shale sample;

[0007] The target shale sample was subjected to isothermal evaporation treatment, and sample mass data and nuclear magnetic resonance monitoring data were collected at multiple time points during the isothermal evaporation process;

[0008] Based on the sample quality data and the nuclear magnetic resonance monitoring data, a time-porosity curve is constructed; and based on the time-porosity curve, the porosity range corresponding to the free oil evaporation stage is determined.

[0009] Extract the first nuclear magnetic resonance monitoring data at the start time and the second nuclear magnetic resonance monitoring data at the end time from the nuclear magnetic resonance monitoring data at the multiple time points, and calculate the change in clay adsorbed water content based on the first nuclear magnetic resonance monitoring data and the second nuclear magnetic resonance monitoring data;

[0010] The free oil content of the target shale sample is determined based on the change in porosity range and the amount of water adsorbed by the clay.

[0011] In one embodiment, constructing a time-porosity curve based on the sample mass data and the nuclear magnetic resonance monitoring data includes:

[0012] Based on the sample mass data, the changes in evaporation mass at multiple time points were determined;

[0013] Based on the nuclear magnetic resonance monitoring data, the changes in pore response at multiple time points were determined;

[0014] Based on the change in evaporation mass and the change in pore response, the evaporation porosity values ​​corresponding to multiple time points are determined;

[0015] A time-porosity curve was constructed based on the evaporation time and the corresponding evaporation porosity value at multiple time points.

[0016] In one embodiment, determining the porosity range corresponding to the free oil evaporation stage based on the time-porosity curve includes:

[0017] Based on the time-porosity curve, the porosity change between each adjacent preset time point is calculated to determine the porosity change rate corresponding to each time period.

[0018] The time period corresponding to the porosity change rate being greater than a preset rate threshold is defined as the target time period.

[0019] Based on the evaporation porosity values ​​corresponding to multiple time points within the target time period, the porosity range of the free oil evaporation stage is determined.

[0020] In one embodiment, the step of extracting first NMR monitoring data at the start time and second NMR monitoring data at the end time from the NMR monitoring data at the plurality of time points, and calculating the change in clay adsorbed water content based on the first NMR monitoring data and the second NMR monitoring data, includes:

[0021] Based on the first nuclear magnetic resonance monitoring data, the initial volume component of water adsorbed by clay was determined;

[0022] Based on the second nuclear magnetic resonance monitoring data, the volume component of clay adsorbed water at each time point was determined;

[0023] The change in clay adsorbed water content was determined based on the initial volume fraction of clay adsorbed water and the volume fraction of clay adsorbed water at each time point.

[0024] In one embodiment, determining the free oil content of the target shale sample based on the change in porosity range and clay adsorbed water content includes:

[0025] Based on the porosity change within the porosity range, determine the porosity increment corresponding to the free oil evaporation stage;

[0026] The porosity increment is corrected based on the change in the water content adsorbed by the clay to obtain the corrected free oil porosity.

[0027] The free oil content of the target shale sample is calculated based on the corrected free oil porosity and the volume of the target shale sample.

[0028] In one embodiment, obtaining a shale sample from a target area and performing fluid existence state recovery processing on the shale sample to obtain the target shale sample includes:

[0029] Based on the formation pressure and formation temperature data of the target area, the acquired shale sample is subjected to corresponding pressure loading and temperature control treatment, so that the shale sample is maintained at the pressure and temperature for a preset duration, so that the pore fluid meets the preset storage requirements.

[0030] Shale samples that meet the preset storage requirements are identified as the target shale samples.

[0031] In one embodiment, the method further includes:

[0032] Based on the free oil content of the target shale sample and the preset oil content evaluation threshold, the fluidity evaluation level of the target shale sample in the reservoir is determined.

[0033] Based on the aforementioned liquidity evaluation level, evaluation factors are generated for identifying sweet spots in shale oil reservoirs.

[0034] This specification provides a device for determining the free oil content of shale samples, including:

[0035] The sample determination module is used to acquire shale samples from the target area and perform fluid storage state recovery processing on the shale samples to obtain the target shale sample;

[0036] The data determination module is used to perform isothermal evaporation treatment on the target shale sample and collect sample quality data and nuclear magnetic resonance monitoring data at multiple time points during the isothermal evaporation process.

[0037] The interval determination module is used to construct a time-porosity curve based on the sample quality data and the nuclear magnetic resonance monitoring data; and to determine the porosity interval corresponding to the free oil evaporation stage based on the time-porosity curve.

[0038] The change determination module is used to extract the first nuclear magnetic resonance monitoring data at the start time and the second nuclear magnetic resonance monitoring data at the end time from the nuclear magnetic resonance monitoring data at the multiple time points, and to calculate the change in clay adsorbed water content based on the first nuclear magnetic resonance monitoring data and the second nuclear magnetic resonance monitoring data.

[0039] The free oil determination module is used to determine the free oil content of the target shale sample based on the change in the porosity range and the amount of adsorbed water content in the clay.

[0040] This specification also provides an electronic device, including a processor and a memory for storing processor-executable instructions, wherein the processor, when executing the instructions, implements a method for determining the free oil content of a shale sample.

[0041] This specification also provides a computer-readable storage medium storing computer instructions that, when executed, implement a method for determining the free oil content of a shale sample.

[0042] Based on the method for determining the free oil content of shale samples provided in this specification, shale samples from a target area are obtained, and fluid storage state restoration processing is performed on the shale samples to obtain target shale samples. The target shale samples are then subjected to isothermal evaporation treatment, and sample mass data and nuclear magnetic resonance (NMR) monitoring data are collected at multiple time points during the isothermal evaporation process. A time-porosity curve is constructed based on the sample mass data and the NMR monitoring data. Based on the time-porosity curve, the porosity interval corresponding to the free oil evaporation stage is determined. First NMR monitoring data at the start time and second NMR monitoring data at the end time are extracted from the NMR monitoring data at the multiple time points, and the change in clay adsorbed water content is calculated based on the first and second NMR monitoring data. The free oil content of the target shale sample is determined based on the porosity interval and the change in clay adsorbed water content. In this way, by first performing fluid occurrence state restoration processing on shale samples from the target area, after identifying the target shale sample, subsequent measurements are conducted around samples that are close to the in-situ state of the formation, reducing the impact of changes in sample occurrence state on the determination of free oil content. Subsequently, during the isothermal evaporation process, sample mass data and corresponding nuclear magnetic resonance monitoring data are simultaneously collected at multiple time points, and a time-porosity curve is constructed based on the two. Then, based on this time-porosity curve, the porosity range corresponding to the free oil evaporation stage is determined, ensuring that the free oil evaporation process is synchronized in terms of time and porosity. A clear characterization in terms of dimensions is beneficial for distinguishing the contribution of pore fluid at different stages. Furthermore, based on the first and second nuclear magnetic resonance monitoring data, the change in clay adsorbed water content is calculated, and the porosity range is combined with the change in clay adsorbed water content when determining the free oil content of the target shale sample. This effectively deducts the interference of clay adsorbed water when determining the free oil content, making the determined free oil content closer to the actual fluid occurrence of the target shale sample after the fluid occurrence state is restored, thus improving the accuracy and reliability of the free oil content determination results. Attached Figure Description

[0043] To more clearly illustrate the embodiments of this specification, the accompanying drawings used in the embodiments will be briefly introduced below. The drawings described below are only some embodiments recorded in this specification. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0044] Figure 1 This is a schematic flowchart illustrating a method for determining the free oil content in shale samples, provided in one embodiment of this specification.

[0045] Figure 2 This is a schematic diagram of the electronic device structure provided in one embodiment of this specification;

[0046] Figure 3 This is a schematic diagram of the structural composition of a device for determining the free oil content of shale samples, provided in one embodiment of this specification.

[0047] Figure 4 This is a schematic diagram illustrating how the evaporation rate determines the content of a rapidly evaporating component, as provided in one embodiment of this specification.

[0048] Figure 5 This is a schematic diagram illustrating the detection of adsorbed water evaporation in clay using nuclear magnetic resonance spectroscopy, as provided in one embodiment of this specification.

[0049] Figure 6 This is a schematic diagram of the superimposed nuclear magnetic resonance spectra of different states, including the original state, self-absorbing oil, and self-absorbing water, provided by one embodiment of this specification;

[0050] Figure 7 This is a schematic diagram of the superimposed nuclear magnetic resonance spectra of an oil bath before and after heating to the formation temperature and after the evaporation is completed, provided as an embodiment of this specification;

[0051] Figure 8 This is an embodiment of the present specification, providing an evaporation curve and a schematic diagram for determining the content of fast and slow evaporation components. Detailed Implementation

[0052] To enable those skilled in the art to better understand the technical solutions in this specification, the technical solutions in the embodiments of this specification will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this specification, and not all embodiments. Based on the embodiments in this specification, all other embodiments obtained by those skilled in the art without creative effort should fall within the scope of protection of this specification.

[0053] See Figure 1As shown in the embodiments of this specification, a method for determining the free oil content of shale samples is provided, wherein the method is specifically applied to the server side. In specific implementation, the method may include the following:

[0054] S101: Obtain shale samples from the target area and perform fluid storage state recovery processing on the shale samples to obtain the target shale samples;

[0055] S102: The target shale sample is subjected to isothermal evaporation treatment, and sample quality data and nuclear magnetic resonance monitoring data are collected at multiple time points during the isothermal evaporation process;

[0056] S103: Based on the sample quality data and the nuclear magnetic resonance monitoring data, construct a time-porosity curve; and based on the time-porosity curve, determine the porosity range corresponding to the free oil evaporation stage;

[0057] S104: Extract the first nuclear magnetic resonance monitoring data at the start time and the second nuclear magnetic resonance monitoring data at the end time from the nuclear magnetic resonance monitoring data at the multiple time points, and calculate the change in clay adsorbed water content based on the first nuclear magnetic resonance monitoring data and the second nuclear magnetic resonance monitoring data;

[0058] S105: Determine the free oil content of the target shale sample based on the change in porosity range and the amount of adsorbed water content in the clay.

[0059] The aforementioned fluid occurrence state can be used to characterize the existence mode of fluid in the pore system of shale samples. It is affected by the formation pressure, formation temperature and rock pore structure, including the distribution characteristics of free oil, bound oil and adsorbed water in the pores.

[0060] The aforementioned nuclear magnetic resonance (NMR) monitoring data can be time-series response signals acquired by NMR instruments, used to reflect the relaxation characteristics of pore fluids in shale samples. This data can distinguish the changes in different types of fluids during the evaporation process, including the NMR relaxation components corresponding to free oil, bound oil, and adsorbed water, providing a basis for judging changes in porosity and water-oil distribution during evaporation.

[0061] The aforementioned time-porosity curve can be constructed by pairing the evaporation porosity at multiple time points during the evaporation process with the corresponding evaporation time, reflecting the trend of porosity change with the evaporation process. This curve can describe the rate difference of fluid escape, and in particular, can distinguish between the free oil evaporation stage and the adsorbed water response stage, providing a basis for subsequently determining the characteristic range corresponding to free oil evaporation.

[0062] The aforementioned free oil evaporation stage refers to the period during isothermal evaporation where oily substances existing in a free state in the pores rapidly evaporate, causing a significant change in porosity. This stage is typically accompanied by a high evaporation rate and a significant decrease in mass, forming a characteristic rapid change segment on the time-porosity curve, serving as an important basis for identifying the contribution of free oil.

[0063] The aforementioned clay adsorbed water content can be used to describe the amount of adsorbed water bound to the surface of clay minerals in shale samples. Its variation can be calculated from the difference between the start and end of nuclear magnetic resonance monitoring data. This parameter is used to identify the amount of adsorbed water interference during the evaporation process, so as to correct the porosity increment when calculating the free oil content and ensure the accuracy of the results.

[0064] The aforementioned free oil content can be used to quantitatively characterize the total amount of oily substances in shale samples that exist in a free state and can be rapidly released during isothermal evaporation. The free oil content calculated jointly by porosity range and changes in clay adsorbed water can more accurately reflect the actual level of mobile fluids in the reservoir, providing crucial evidence for shale oil reservoir evaluation and sweet spot identification.

[0065] In some embodiments, the isothermal evaporation treatment of the target shale sample, and the collection of sample quality data and nuclear magnetic resonance monitoring data at multiple time points during the isothermal evaporation process, may specifically include:

[0066] The target shale sample, after undergoing fluid-endowment state restoration treatment, is placed inside the sample chamber of the evaporation device. The temperature control parameters of the isothermal heating unit are set according to the preset formation simulation temperature, ensuring stable operation within the chamber. Before evaporation begins, the sample is initially weighed, and the nuclear magnetic resonance (NMR) detection module is activated to acquire initial NMR monitoring data before evaporation. Subsequently, the isothermal heating unit is activated, allowing the sample to enter the evaporation process at a stable temperature.

[0067] During the evaporation process, the control data acquisition module triggers the weighing unit at preset sampling time intervals to record the remaining mass of the sample, obtaining sample mass data at multiple time points. Simultaneously, the control nuclear magnetic resonance (NMR) detection module acquires NMR monitoring data at multiple time points consistent with the mass sampling to reflect changes in the relaxation signal of the pore fluid during evaporation. To ensure the consistency of the acquired data, the data acquisition module synchronously records the current temperature stability of the heating unit at each time point, ensuring that the evaporation process remains at a constant temperature.

[0068] After data acquisition at multiple time points is completed, the sample is removed from the chamber and the evaporation process is terminated. The mass data recorded during the evaporation process and the nuclear magnetic resonance monitoring data are stored in the data processing module for subsequent construction of time-porosity curves and identification of the free oil evaporation stage.

[0069] In some embodiments, the step of extracting first NMR monitoring data at the start time and second NMR monitoring data at the end time from the NMR monitoring data at the plurality of time points, and calculating the change in clay adsorbed water content based on the first NMR monitoring data and the second NMR monitoring data, may specifically include:

[0070] Before the isothermal evaporation begins, the control nuclear magnetic resonance (NMR) detection module performs a complete relaxation signal acquisition on the target shale sample to obtain NMR monitoring data at the start of evaporation, and stores this monitoring data as the first NMR monitoring data. As the evaporation process proceeds, the control NMR detection module triggers monitoring again at the preset end of evaporation time point and acquires the relaxation signal of the sample at the end of evaporation, storing this monitoring data as the second NMR monitoring data.

[0071] Subsequently, the first and second NMR monitoring data are input into the data processing module. The data processing module compares and analyzes the relaxation intervals corresponding to clay adsorbed water in the two sets of monitoring data, extracts the signal amplitude change or corresponding integral change of the characteristic peak of adsorbed water, and uses this change as the change in clay adsorbed water content. Through this processing, the response change of adsorbed water in the porous system before and after evaporation can be quantified, providing data support for porosity correction in subsequent calculations of free oil content.

[0072] In some embodiments, the method of constructing a time-porosity curve based on the sample mass data and the nuclear magnetic resonance monitoring data may further include the following:

[0073] S1: Based on the sample mass data, determine the change in evaporation mass at multiple time points;

[0074] S2: Based on the nuclear magnetic resonance monitoring data, determine the changes in pore response at multiple time points;

[0075] S3: Determine the evaporation porosity values ​​corresponding to multiple time points based on the change in evaporation mass and the change in pore response;

[0076] S4: Construct a time-porosity curve based on the evaporation time and corresponding evaporation porosity value at multiple time points.

[0077] Specifically, during the isothermal evaporation process, the target shale sample is weighed at multiple preset time points to obtain the sample mass at each time point, and the initial mass at the start of evaporation is used as the baseline mass. The difference between the sample mass at each time point and the baseline mass is obtained to obtain the evaporation mass change at multiple time points, which is used to characterize the mass change trend over time during the evaporation process.

[0078] Simultaneously, nuclear magnetic resonance (NMR) detection was triggered at the same time point as the mass acquisition to record the pore response of the sample during evaporation, obtaining multiple sets of NMR monitoring signals reflecting the relaxation characteristics of the pore fluid. By comparing the monitoring signals at each time point with the initial monitoring signal at the start of evaporation, the change in pore response at each time point was determined, which is used to represent the change in fluid distribution within the pores caused by evaporation.

[0079] After obtaining the changes in evaporation mass and pore response at each time point, the two are analyzed in correspondence. Based on the mapping relationship between mass loss and pore response change, the evaporation porosity values ​​corresponding to multiple time points are calculated to characterize the dynamic increment of porosity during evaporation.

[0080] Subsequently, the evaporation porosity values ​​at each time point were paired with their corresponding evaporation times and arranged in chronological order to plot a porosity-evaporation time curve, i.e., a time-porosity curve. This curve is used to characterize the overall trend of porosity changes during the evaporation stage, providing basic data for identifying the free oil evaporation stage.

[0081] In some embodiments, the method for determining the porosity range corresponding to the free oil evaporation stage based on the time-porosity curve may further include the following:

[0082] S1: Based on the time-porosity curve, calculate the porosity change between each adjacent preset time point to determine the porosity change rate corresponding to each time period.

[0083] S2: The time period corresponding to the porosity change rate being greater than a preset rate threshold is determined as the target time period;

[0084] S3: Determine the porosity range of the free oil evaporation stage based on the evaporation porosity values ​​corresponding to multiple time points within the target time period.

[0085] Specifically, after constructing the time-porosity curve, the evaporation porosity values ​​corresponding to two adjacent preset time points on the curve are read, and the porosity change between adjacent time points is calculated accordingly. Subsequently, the porosity change is divided by the time interval between adjacent time points to obtain the porosity change rate for each time period, which reflects the speed of porosity growth during the evaporation process.

[0086] After obtaining the porosity change rate for all time periods, the rate for each time period is compared with a preset rate threshold. When the porosity change rate for a certain time period is greater than the rate threshold, that time period is recorded as the target time period to identify a stage where the evaporation rate increases significantly. This stage usually coincides with the rapid evaporation of free oil in the pores.

[0087] Subsequently, multiple time points corresponding to the target time period were screened, and the evaporation porosity values ​​of these time points on the time-porosity curve were read. These evaporation porosity values ​​were then summarized in chronological order, and their upper and lower limits were taken as the porosity range of the free oil evaporation stage. This range is used to reflect the porosity change range during the free oil evaporation process, providing a basis for subsequently distinguishing the response contribution of free oil and clay adsorbed water.

[0088] In some embodiments, the method involves extracting first NMR monitoring data at the start time and second NMR monitoring data at the end time from the NMR monitoring data at the plurality of time points, and calculating the change in clay adsorbed water content based on the first NMR monitoring data and the second NMR monitoring data. In specific implementations, the method may further include the following:

[0089] S1: Determine the initial volume component of water adsorbed by clay based on the first nuclear magnetic resonance monitoring data;

[0090] S2: Determine the volume component of clay adsorbed water at each time point based on the second nuclear magnetic resonance monitoring data;

[0091] S3: Determine the change in clay adsorbed water content based on the initial volume component of clay adsorbed water and the volume component of clay adsorbed water at each time point.

[0092] Before the isothermal evaporation begins, a nuclear magnetic resonance (NMR) measurement is performed on the target shale sample to obtain the first NMR monitoring data at the evaporation initiation time. The relaxation signal in this initial monitoring data is analyzed, and based on the relaxation characteristic interval corresponding to the clay adsorbed water in the NMR spectrum, the signal integral quantity related to the adsorbed water is extracted and converted into the initial volume component of clay adsorbed water.

[0093] At the preset end time point of the evaporation process, nuclear magnetic resonance (NMR) measurements are performed on the shale sample again to obtain second NMR monitoring data at the end of evaporation. This monitoring data undergoes the same relaxation interval extraction and integration process to obtain the volume component of adsorbed water in the clay at the end of evaporation. If necessary, the same processing can be performed on NMR monitoring data from multiple time points during the evaporation process to observe the overall trend of the adsorbed water volume component during evaporation.

[0094] Subsequently, the initial volume component of clay-adsorbed water was compared with the volume component of clay-adsorbed water at the end of evaporation. The change in clay-adsorbed water content was determined as a difference, reflecting the reduction in adsorbed water content due to temperature-driven factors during evaporation. This method allows for direct identification of the response changes of adsorbed water in the porous system before and after evaporation without relying on mass measurements, providing a basis for correcting porosity increments in subsequent free oil calculations.

[0095] In some embodiments, the step of extracting the first NMR monitoring data at the start time and the second NMR monitoring data at the end time from the NMR monitoring data at the plurality of time points, and calculating the change in clay adsorbed water content based on the first NMR monitoring data and the second NMR monitoring data, may further include: performing quantitative analysis based on the difference in spectral peak integrals.

[0096] Specifically, in the first NMR monitoring data collected before evaporation begins, the spectral peaks during the low relaxation period are integrated to obtain the initial signal integral value corresponding to clay adsorbed water. During the isothermal evaporation process, when evaporation enters the free oil evaporation stage, the spectral peaks during the low relaxation period are similarly extracted from the second NMR monitoring data collected and integrated to obtain the integral value of the clay adsorbed water signal for this stage.

[0097] Since the NMR response of clay-adsorbed water is mainly concentrated in the low relaxation time range, and the peak area is positively correlated with the content, the change in clay-adsorbed water content can be determined by comparing the difference between two integral values. If the second integral value is less than the initial integral value, it indicates that clay-adsorbed water has been released or evaporated during the evaporation process, and the difference is the amount of reduction in clay-adsorbed water content.

[0098] The above embodiments quantify the changes in clay adsorbed water by integrating spectral peaks, which is more suitable for measurement environments with high signal noise and where it is difficult to directly and accurately extract the volume component at a single time point. At the same time, it can avoid volume component errors caused by unstable parameter fitting and improve the stability of the change calculation.

[0099] In some embodiments, the method for determining the free oil content of the target shale sample based on the change in porosity range and clay adsorbed water content may further include the following:

[0100] S1: Determine the porosity increment corresponding to the free oil evaporation stage based on the porosity change within the porosity range;

[0101] S2: Based on the change in the water content adsorbed by the clay, the porosity increment is corrected to obtain the corrected free oil porosity;

[0102] S3: Calculate the free oil content of the target shale sample based on the corrected free oil porosity and the volume of the target shale sample.

[0103] Specifically, after identifying the porosity range corresponding to the free oil evaporation stage, the evaporation porosity values ​​at each time point within the range are statistically analyzed. By accumulating the porosity differences between adjacent time points, the total porosity change during the evaporation stage is obtained. This total change is determined as the porosity increment corresponding to the free oil evaporation stage, which is used to characterize the contribution of free oil evaporation to porosity.

[0104] Subsequently, the calculated change in clay adsorbed water content is compared with the porosity increment. By subtracting the porosity contribution corresponding to adsorbed water evaporation from the porosity increment, a corrected porosity caused solely by free oil evaporation is obtained. This correction process eliminates the interference of adsorbed water evaporation on porosity measurement, making the calculated porosity change more accurately reflect the actual amount of free oil evaporation.

[0105] After obtaining the corrected free oil porosity, the porosity is converted into the corresponding oil phase volume based on the volume parameters of the target shale sample to obtain the free oil content of the sample. This calculation process converts the change in porosity into a quantifiable free oil volume through the proportional relationship between porosity and volume, thereby achieving accurate determination of free oil substances in shale samples.

[0106] In some embodiments, determining the free oil content of the target shale sample based on the change in porosity range and the clay adsorbed water content may further include:

[0107] After identifying the porosity range during the free oil evaporation stage, the porosity change curve within this range is fitted. Linear or polynomial fitting methods are used to obtain a porosity change fitting curve reflecting the evaporation trend. The difference between the start and end points of this fitting curve within the range is taken as the porosity increment during the free oil evaporation stage. This method eliminates the influence of noise at individual sampling points on the porosity increment, making the porosity extraction process smoother.

[0108] Subsequently, based on the change in clay adsorbed water content calculated from the nuclear magnetic resonance monitoring data before and after evaporation, this change was converted into a porosity contribution value according to a preset adsorbed water response coefficient. This contribution value was then subtracted from the porosity increment to obtain the free oil porosity corrected for adsorbed water. By introducing the adsorbed water response coefficient, the response ranges of free oil and adsorbed water can be more stably distinguished even in the presence of monitoring noise or multi-peak relaxation distribution.

[0109] After obtaining the corrected free oil porosity, the porosity is multiplied by the sample volume based on the target shale sample volume to obtain the corresponding free oil volume, thus determining the free oil content of the sample. The above alternative embodiment achieves robust extraction of free oil porosity through curve fitting and coefficient conversion, further improving the stability of the calculation results in samples with large data fluctuations or high clay content.

[0110] In some embodiments, the method of obtaining shale samples from the target area and performing fluid storage state recovery processing on the shale samples to obtain the target shale sample may further include the following:

[0111] S1: Based on the formation pressure data and formation temperature data of the target area, apply corresponding pressure loading and temperature control to the acquired shale sample, so that the shale sample is maintained at the pressure and temperature for a preset time, so that the pore fluid meets the preset storage requirements.

[0112] S2: The shale sample that meets the preset storage requirements is identified as the target shale sample.

[0113] Specifically, based on the formation pressure and temperature data of the well section where the shale sample is located, the confining pressure and pore pressure parameters of the pressure loading device are set, and the heating temperature of the isothermal system is set to ensure that the sample is in a pressure and temperature environment consistent with the target area formation. Before placing the sample, the pressure chamber and heating chamber are pre-adjusted to reach the set pressure and temperature.

[0114] Subsequently, the shale sample to be processed is placed in a pressure chamber, and the pressure loading and temperature control process is initiated, maintaining the sample at the set pressure and temperature for a predetermined duration, such as 12 to 48 hours. During this process, the pore fluid within the sample gradually redistributes, causing the free oil, bound oil, and adsorbed water in the pores to stabilize under the influence of external stress and thermal conditions, restoring them to a state close to that of the target reservoir. Researchers can use the stability of the nuclear magnetic resonance signal collected before evaporation to help determine whether the pore fluid has met the preset storage requirements.

[0115] Once the sample has been maintained under the specified pressure and temperature for the preset duration, the loading and temperature control process is terminated. The sample that has reached a stable state is then removed and identified as the target shale sample for subsequent isothermal evaporation measurements and free oil content analysis.

[0116] In some embodiments, the step of obtaining shale samples from the target area and performing fluid storage state recovery processing on the shale samples to obtain the target shale sample may further include: implementing it using a step-by-step loading method.

[0117] Specifically, after obtaining formation pressure and temperature data for the target area, the shale sample is first placed in a sealed loading chamber. Before the chamber is fully subjected to the target pressure, the pressure on the sample is gradually increased in small increments to approach the target formation pressure. For example, the total pressure is divided into several levels, each maintained for a certain duration, to avoid sudden loading that could cause non-native deformation of the pore structure. Simultaneously, the chamber is heated, gradually raising the temperature to the formation temperature of the target area.

[0118] After the pressure and temperature at each level reach the target values, the sample is allowed to remain stationary at the target pressure and temperature to allow the fluid within the pores to redistribute and form a stable fluid state. Researchers can confirm that the pore fluid has reached a stable state by detecting the changing trend of the initial nuclear magnetic resonance signal. If the signal changes consistently over multiple acquisitions, it can be considered that the preset fluid state requirements have been met.

[0119] Once the sample has completed the above-mentioned progressive loading and stabilization stages, it can be identified as the target shale sample for subsequent evaporation measurements and free oil analysis.

[0120] In some embodiments, the method may further include the following:

[0121] S1: Determine the fluidity evaluation level of the target shale sample in the reservoir based on the free oil content of the target shale sample and the preset oil content evaluation threshold;

[0122] S2: Based on the aforementioned liquidity evaluation level, generate evaluation factors for identifying sweet spots in shale oil reservoirs.

[0123] Specifically, after determining the free oil content of the target shale sample, the system compares this free oil content with a preset oil-bearing evaluation threshold. The oil-bearing evaluation threshold is pre-set based on the geological characteristics, pore structure type, and actual development experience of the target area reservoir, and is divided into multiple threshold intervals corresponding to different oil-bearing levels. For example, it may include a first threshold interval representing low liquidity, a second threshold interval representing medium liquidity, and a third threshold interval representing high liquidity. When the free oil content falls within a certain threshold interval, the system determines the sample's liquidity evaluation level to the level corresponding to that threshold interval.

[0124] After obtaining the liquidity rating, the system further generates evaluation factors for identifying sweet spots in shale oil reservoirs based on that rating. Specifically, the system can assign different evaluation weights to different ratings, using these weights as the final evaluation factors. For example, if a target shale sample is determined to have a high liquidity rating, a higher evaluation factor is assigned to it; if it is determined to have a low liquidity rating, a lower evaluation factor is assigned. These evaluation factors can be directly used as inputs in the subsequent shale oil reservoir sweet spot identification model to characterize the oil-bearing potential and liquidity status of the corresponding formation unit under actual production conditions.

[0125] Through the above implementation methods, quantifiable parameters required for geological evaluation can be directly constructed based on the obtained free oil content, enabling complex experimental measurement results to be transformed into effective input data for reservoir evaluation, thereby improving the accuracy and automation of the shale oil sweet spot identification process.

[0126] In some embodiments, the method may further include the following:

[0127] After determining the free oil content of the target shale sample, a fluidity index reflecting the sample's fluid flow capacity is first calculated based on the difference between this free oil content and a preset oil content evaluation threshold. This fluidity index quantifies the target sample's free oil replenishment capacity and pore connectivity; a higher index value indicates a greater amount of usable oil in the actual reservoir environment.

[0128] After obtaining the liquidity index, it is further mapped to multiple discrete grade intervals to form the liquidity evaluation grade of the target shale sample. The mapping method can be implemented through linear piecewise division or by looking up a table to ensure clear boundaries and differentiation between different grades.

[0129] Subsequently, based on the liquidity evaluation level, a corresponding evaluation factor is assigned to that level. The evaluation factors can adopt a gradient-increasing structure, for example, assigning higher factor values ​​to higher levels to enhance the sample's contribution to the subsequent sweet spot identification process. There is a one-to-one correspondence between the evaluation factors and the liquidity evaluation level, which can serve as input items in subsequent geological modeling or reservoir evaluation algorithms, directly participating in the comprehensive identification of reservoir sweet spot zones.

[0130] Through the above alternative embodiments, a more continuous evaluation system can be constructed through index mapping without changing the calculation method of free oil content, making it easier to quantify the differences between different samples, while improving the sensitivity and applicability of the subsequent dessert evaluation process.

[0131] As can be seen from the above, the method for determining the free oil content of shale samples provided in this specification involves obtaining shale samples from a target area and performing fluid storage state recovery processing on the shale samples to obtain target shale samples; performing isothermal evaporation treatment on the target shale samples and collecting sample mass data and nuclear magnetic resonance (NMR) monitoring data at multiple time points during the isothermal evaporation process; constructing a time-porosity curve based on the sample mass data and the NMR monitoring data; determining the porosity interval corresponding to the free oil evaporation stage based on the time-porosity curve; extracting the first NMR monitoring data at the start time point and the second NMR monitoring data at the end time point from the NMR monitoring data at the multiple time points, and calculating the change in clay adsorbed water content based on the first NMR monitoring data and the second NMR monitoring data; and determining the free oil content of the target shale sample based on the porosity interval and the change in clay adsorbed water content. In this way, by first performing fluid occurrence state restoration processing on shale samples from the target area, after identifying the target shale sample, subsequent measurements are conducted around samples that are close to the in-situ state of the formation, reducing the impact of changes in sample occurrence state on the determination of free oil content. Subsequently, during the isothermal evaporation process, sample mass data and corresponding nuclear magnetic resonance monitoring data are simultaneously collected at multiple time points, and a time-porosity curve is constructed based on the two. Then, based on this time-porosity curve, the porosity range corresponding to the free oil evaporation stage is determined, ensuring that the free oil evaporation process is synchronized in terms of time and porosity. A clear characterization in terms of dimensions is beneficial for distinguishing the contribution of pore fluid at different stages. Furthermore, based on the first and second nuclear magnetic resonance monitoring data, the change in clay adsorbed water content is calculated, and the porosity range is combined with the change in clay adsorbed water content when determining the free oil content of the target shale sample. This effectively deducts the interference of clay adsorbed water when determining the free oil content, making the determined free oil content closer to the actual fluid occurrence of the target shale sample after the fluid occurrence state is restored, thus improving the accuracy and reliability of the free oil content determination results.

[0132] See Figure 2 As shown in the embodiments of this specification, a specific electronic device is also provided, wherein the electronic device includes a network communication port 201, a processor 202 and a memory 203, and the above structures are connected by internal cables so that the various structures can perform specific data interaction.

[0133] Specifically, the network communication port 201 can be used to acquire shale samples from the target area and perform fluid storage state recovery processing on the shale samples to obtain the target shale samples.

[0134] The processor 202 is specifically used to perform isothermal evaporation treatment on the target shale sample, and collect sample mass data and nuclear magnetic resonance (NMR) monitoring data at multiple time points during the isothermal evaporation process; construct a time-porosity curve based on the sample mass data and the NMR monitoring data; determine the porosity interval corresponding to the free oil evaporation stage based on the time-porosity curve; extract the first NMR monitoring data at the start time point and the second NMR monitoring data at the end time point from the NMR monitoring data at the multiple time points, and calculate the change in clay adsorbed water content based on the first NMR monitoring data and the second NMR monitoring data; determine the free oil content of the target shale sample based on the porosity interval and the change in clay adsorbed water content.

[0135] The memory 203 can be used to store the corresponding instruction program.

[0136] Based on the above method, the relevant structural performance of electronic equipment can be effectively utilized to improve the data processing speed of electronic equipment and efficiently realize a method for determining the free oil content of shale samples.

[0137] In this embodiment, the network communication port 201 can be a virtual port bound to different communication protocols, thereby enabling the sending or receiving of different data. For example, the network communication port can be a port responsible for web data communication, a port responsible for FTP data communication, or a port responsible for email data communication. Furthermore, the network communication port can also be a physical communication interface or communication chip. For example, it can be a wireless mobile network communication chip, such as GSM or CDMA; it can also be a Wi-Fi chip; or it can be a Bluetooth chip.

[0138] In this embodiment, the processor 202 can be implemented in any suitable manner. For example, the processor can take the form of a microprocessor or processor and a computer-readable medium storing computer-readable program code (e.g., software or firmware) executable by the (micro)processor, logic gates, switches, application-specific integrated circuits (ASICs), programmable logic controllers, and embedded microcontrollers, etc. This specification is not limiting.

[0139] In this embodiment, the memory 203 may include a hierarchy. In a digital system, anything that can store binary data can be a memory. In an integrated circuit, a circuit with storage function but no physical form is also called a memory, such as RAM, FIFO, etc. In a system, a storage device with a physical form is also called a memory, such as a memory stick, TF card, etc.

[0140] This specification also provides a computer-readable storage medium based on the above-described method for determining the free oil content of shale samples. The method involves acquiring shale samples from a target area and performing fluid storage state recovery processing on the shale samples to obtain target shale samples; performing isothermal evaporation on the target shale samples and collecting sample mass data and nuclear magnetic resonance (NMR) monitoring data at multiple time points during the isothermal evaporation process; constructing a time-porosity curve based on the sample mass data and the NMR monitoring data; determining the porosity interval corresponding to the free oil evaporation stage based on the time-porosity curve; extracting first NMR monitoring data at the start time point and second NMR monitoring data at the end time point from the NMR monitoring data at the multiple time points; calculating the change in clay adsorbed water content based on the first NMR monitoring data and the second NMR monitoring data; and determining the free oil content of the target shale sample based on the porosity interval and the change in clay adsorbed water content.

[0141] In this embodiment, the storage medium includes, but is not limited to, Random Access Memory (RAM), Read-Only Memory (ROM), Cache, Hard Disk Drive (HDD), or Memory Card. The memory can be used to store computer program instructions. The network communication unit can be an interface configured according to standards specified in the communication protocol for network connection communication.

[0142] In this embodiment, the specific functions and effects implemented by the program instructions stored in the computer-readable storage medium can be explained in comparison with other embodiments, and will not be repeated here.

[0143] See Figure 3 At the software level, this specification also provides a device for determining the free oil content of shale samples, which may specifically include the following structural modules:

[0144] The sample determination module 301 is used to acquire shale samples from the target area and perform fluid storage state recovery processing on the shale samples to obtain the target shale samples;

[0145] The data determination module 302 is used to perform isothermal evaporation treatment on the target shale sample and collect sample quality data and nuclear magnetic resonance monitoring data at multiple time points during the isothermal evaporation process.

[0146] The interval determination module 303 is used to construct a time-porosity curve based on the sample quality data and the nuclear magnetic resonance monitoring data; and to determine the porosity interval corresponding to the free oil evaporation stage based on the time-porosity curve.

[0147] The change determination module 304 is used to extract the first nuclear magnetic resonance monitoring data at the start time and the second nuclear magnetic resonance monitoring data at the end time from the nuclear magnetic resonance monitoring data at the multiple time points, and to calculate the change in the clay adsorbed water content based on the first nuclear magnetic resonance monitoring data and the second nuclear magnetic resonance monitoring data.

[0148] The free oil determination module 305 is used to determine the free oil content of the target shale sample based on the change in the porosity range and the amount of adsorbed water content in the clay.

[0149] In some embodiments, the interval determination module 303, in specific implementation, determines the evaporation mass change at multiple time points based on the sample mass data; determines the pore response change at multiple time points based on the nuclear magnetic resonance monitoring data; determines the evaporation porosity value corresponding to multiple time points based on the evaporation mass change and the pore response change; and constructs a time-porosity curve based on the evaporation time and the corresponding evaporation porosity value at multiple time points. Based on the time-porosity curve, the porosity change between adjacent preset time points is calculated to determine the porosity change rate corresponding to each time period; the time period corresponding to the porosity change rate being greater than a preset rate threshold is determined as the target time period; and the porosity interval of the free oil evaporation stage is determined based on the evaporation porosity values ​​corresponding to multiple time points within the target time period.

[0150] In some embodiments, the change determination module 304, in specific implementation, determines the initial volume component of clay-adsorbed water based on the first nuclear magnetic resonance monitoring data; determines the volume component of clay-adsorbed water at each time point based on the second nuclear magnetic resonance monitoring data; and determines the change in clay-adsorbed water content based on the initial volume component of clay-adsorbed water and the volume component of clay-adsorbed water at each time point.

[0151] In some embodiments, the free oil determination module 305, in specific implementation, determines the porosity increment corresponding to the free oil evaporation stage based on the porosity change within the porosity range; corrects the porosity increment based on the change in clay adsorbed water content to obtain the corrected free oil porosity; and calculates the free oil content of the target shale sample based on the corrected free oil porosity and the volume of the target shale sample.

[0152] In some embodiments, the sample determination module 301, in specific implementation, applies corresponding pressure loading and performs temperature control on the acquired shale sample based on the formation pressure data and formation temperature data of the target area, so that the shale sample is maintained at the pressure and temperature for a preset duration so that the pore fluid meets the preset storage requirements; the shale sample that meets the preset storage requirements is determined as the target shale sample.

[0153] In some embodiments, the above-described apparatus further includes: determining the fluidity evaluation level of the target shale sample in the reservoir based on the free oil content of the target shale sample and a preset oil content evaluation threshold; and generating an evaluation factor for identifying sweet spots in shale oil layers based on the fluidity evaluation level.

[0154] It should be noted that the units, devices, or modules described in the above embodiments can be implemented by computer chips or physical entities, or by products with certain functions. For ease of description, the above devices are described by dividing them into various modules according to their functions. Of course, in implementing this specification, the functions of each module can be implemented in the same software and / or hardware, or modules that implement the same function can be implemented by a combination of sub-modules or sub-units, etc. The device embodiments described above are merely illustrative. For example, the division of units is only a logical functional division, and there may be other division methods in actual implementation. For example, units or components can be combined or integrated into another system, or some features can be ignored or not executed. Furthermore, the coupling or direct coupling or communication connection between the devices or units shown or discussed can be through some interfaces, and the indirect coupling or communication connection between devices or units can be electrical, mechanical, or other forms.

[0155] As can be seen from the above, based on the shale sample free oil content determination device provided in the embodiments of this specification, shale samples from a target area are obtained, and fluid storage state restoration processing is performed on the shale samples to obtain target shale samples; the target shale samples are subjected to isothermal evaporation treatment, and sample mass data and nuclear magnetic resonance (NMR) monitoring data are collected at multiple time points during the isothermal evaporation process; a time-porosity curve is constructed based on the sample mass data and the NMR monitoring data; and the porosity interval corresponding to the free oil evaporation stage is determined based on the time-porosity curve; the first NMR monitoring data at the start time point and the second NMR monitoring data at the end time point are extracted from the NMR monitoring data at the multiple time points, and the change in clay adsorbed water content is calculated based on the first NMR monitoring data and the second NMR monitoring data; the free oil content of the target shale sample is determined based on the porosity interval and the change in clay adsorbed water content.

[0156] In a specific scenario example, the method and apparatus for determining the free oil content in shale samples provided in this specification can be applied, solving the problem that existing free oil content determination results have large deviations and are difficult to accurately reflect the actual fluid occurrence state in shale pores. The specific implementation process may include the following:

[0157] In some embodiments, the process of restoring the fluid occurrence state specifically involves, in the initial stage of the experiment, structural processing, fluid compensation, and formation temperature restoration treatment of the obtained shale core samples to restore the true fluid occurrence state of the shale samples in the formation as much as possible.

[0158] First, 1.5-inch columnar cores were prepared using wire cutting. Wire cutting avoids mechanical impact, maximizing the preservation of the integrity of rock microfractures and pore structures. Simultaneously, the large core volume allows the sample's fluid saturation to more closely approximate the true formation level, improving the signal-to-noise ratio of subsequent nuclear magnetic resonance (NMR) detection.

[0159] Subsequently, taking advantage of the inherent properties of crude oil and formation water entering the core pores, the core was subjected to self-absorption saturation treatment to compensate for fluid loss during core sampling, preservation, and processing, thus restoring the sample to its original oil- and water-bearing state. After fluid compensation, the core was placed in a stable crude oil bath environment, and by heating and maintaining a constant temperature, the formation temperature was restored, thereby eliminating the influence of temperature differences on the free oil's occurrence state.

[0160] Throughout the recovery process, nuclear magnetic resonance (NMR) technology was used to simultaneously monitor the saturation changes and pore fluid distribution of the rock sample to confirm whether the sample had reached the expected occurrence state. After the above procedures, the target shale sample that meets the experimental requirements can be obtained.

[0161] In some embodiments, the process of simultaneous monitoring of isothermal evaporation and nuclear magnetic resonance involves, specifically, obtaining the target shale sample and placing it in an isothermal drying apparatus for evaporation testing. To ensure temperature stability during the evaporation process, the drying chamber is preheated to the formation temperature and maintained for at least three hours to eliminate temperature fluctuations during the heating process, thereby ensuring that the entire evaporation process is carried out at a constant temperature.

[0162] During the isothermal evaporation process, the mass changes of the sample at multiple time points were recorded in real time using a high-precision electronic balance, while the porosity of the sample was monitored synchronously using nuclear magnetic resonance (NMR) equipment. The mass changes reflect the process of light hydrocarbons and water escaping from the core in the pores, while the NMR signal can record the response changes of pore fluids under different occurrence states.

[0163] By simultaneously acquiring two types of data, high-precision and continuous evaporation curves and porosity change curves can be obtained, providing a reliable data foundation for the analysis of the evaporation characteristics of fluids with different storage types.

[0164] In some embodiments, the calculation of free oil content specifically involves the following steps during the data processing stage: First, the average density of the liquid-gas mixture in the nanopores during evaporation is estimated using the mass of the samples before and after evaporation, as well as the porosity information obtained from nuclear magnetic resonance. Based on this density, the evaporation porosity at a specific time point can be calculated in conjunction with the mass change during evaporation, thereby overcoming the error caused by the mass transfer limitation of nanoscale pores in calculating the evaporation amount.

[0165] Furthermore, the change in evaporation porosity over time was plotted as a cross-plot, and the evaporation rate characteristics of different time periods were analyzed by segmentation. Time periods with higher evaporation rates usually correspond to the rapid evaporation stage of free fluid in the pores. Based on this, the free oil evaporation section can be defined, and the range of evaporation porosity of the free oil can be calculated.

[0166] Meanwhile, by comparing the nuclear magnetic resonance signals before evaporation and at the end of the free oil evaporation stage, the change in clay adsorbed water during the evaporation process was determined. This change reflects the loss of adsorbed water in clay minerals during evaporation, and it needs to be removed from the free oil evaporation porosity to avoid the miscounting of adsorbed water desorption caused by high temperature or evaporation conditions as free oil.

[0167] After correcting for clay adsorption water interference, accurate free oil porosity can be obtained. Further combining this with pre-evaporation nuclear magnetic resonance data, the total oil-bearing porosity and adsorbed oil porosity of the sample can be determined, ultimately yielding the free oil content and adsorbed oil content, thus achieving precise characterization of the oil-bearing state of the shale sample.

[0168] In some embodiments, an experimental procedure for determining the free oil content of shale samples is provided. The main equipment used in the experiment includes a vacuum-pressurization saturation device, a constant temperature oven, an electronic balance, and a nuclear magnetic resonance (NMR) instrument. The key technical parameters are as follows: the core chamber volume of the vacuum-pressurization saturation device is 5000 mL (cylindrical), with a vacuum level of 0.01 MPa and a maximum pressurization capacity of 60 MPa; the temperature control range of the constant temperature oven is 0–150 °C, with a temperature control accuracy of 0.1 °C; the weighing accuracy of the electronic balance is 0.001 g, and the maximum range is 320 g; the NMR instrument uses a CPMG pulse sequence, with a working frequency of 2 MHz, a magnetic field strength of 0.046 T, a waiting time of 7.5 s, an echo interval of 0.1 ms, 64 scans, and 25000 echoes. The above equipment together constitutes the experimental platform for fluid state recovery, constant temperature evaporation testing, and pore fluid response monitoring in this embodiment. In specific implementations, it may include:

[0169] S1: Sample processing and basic parameter determination.

[0170] According to the wellbore nuclear magnetic resonance logging data, the core section had relatively high nuclear magnetic porosity. The sample was designed as a cylinder with a nominal diameter of 1 inch and a length more than 1.5 times the diameter. A total of 6 cores were taken, and the specific parameters are shown in Table 1, Basic Parameter Table of Permian Lucaogou Formation Lower Section Analysis Samples.

[0171] Table 1

[0172]

[0173] S2: Crude oil under vacuum and pressure for 48 hours to achieve self-absorption saturation, nuclear magnetic resonance spectroscopy and quality determination of self-absorption oil samples.

[0174] S3: Formation water was saturated under vacuum and pressure for 48 hours, and nuclear magnetic resonance spectroscopy and mass determination of the self-absorbed water sample were performed.

[0175] S4: Calculation of sample volume V; Since the pore fluid types include clay-adsorbed water and crude oil, the core volume was obtained using the cylinder volume calculation method, and the data are shown in Table 1.

[0176] S5: The core sample was heated to the formation temperature of 120℃ using the crude oil oil bath heating method. After equilibration for 24 hours, the nuclear magnetic resonance spectrum and sample mass M0 were measured.

[0177] S6: Heat the oven to the ground temperature and allow it to equilibrate for 3 hours.

[0178] S7: Place the sample in an oven and evaporate it at a constant temperature under the conditions of the inner layer temperature. Record the evaporation time t. i Measure the mass Mi and nuclear magnetic resonance spectrum after evaporation. Repeat this step until the mass stabilizes.

[0179] S8: Calculate the porosity, water content, and oil content porosity of the sample using nuclear magnetic resonance spectroscopy after self-absorption of water.

[0180] S9: Calculation of the average density of the liquid-vapor mixture formed by the nanopore mass transfer effect.

[0181] S10: Calculation of evaporation porosity of the sample. The evaporation porosity corresponding to different evaporation times is obtained, as shown in Table 2.

[0182] Table 2

[0183]

[0184] S11: Construction of the time-porosity curve: The evaporation time ti (min) at each measurement point is plotted as the x-axis, and the evaporation porosity is plotted as the y-axis. i is the ordinate.

[0185] S12: Quantified the evaporation kinetics (rate differences) of fluids in different occurrence states (especially free oil and adsorbed oil) in nanopores, and determined the content of fast-evaporating components.

[0186] S13: Based on the NMR measurement of clay adsorbed water content change data, the clay adsorbed water evaporation interference of the fast evaporation component content is corrected, and the free oil content is calculated.

[0187] S14: The measurement results of the samples from the lower section of the Jinglucaogou Formation are shown in Table 3.

[0188] Table 3

[0189]

[0190] Using the above experimental data to calibrate the NMR logging data for this well section, the cutoff values ​​for porosity calculation were obtained as follows: 1 ms, 6 ms for oil-bearing porosity calculation, and 35 ms for free oil porosity calculation.

[0191] In some embodiments, see Figure 4 As shown, by plotting the "correspondence between evaporation time and evaporation porosity" obtained from the isothermal evaporation experiment, the trend of porosity change over time during the evaporation process can be visually displayed. Figure 4 The horizontal axis represents evaporation time, and the vertical axis represents the evaporation porosity at the corresponding time point. As can be seen from the graph, the evaporation porosity exhibits rapid growth in the initial stage, followed by a gradual transition to slower growth.

[0192] When performing segmented analysis on the evaporation curve, the location of the inflection point where a significant change occurs during the evaporation process can be identified by comparing the changes in evaporation porosity in adjacent time periods. Figure 4 The vertically marked time points represent the evaporation inflection points, and the corresponding evaporation porosity is represented by horizontally marked values. This evaporation porosity characterizes the porosity when free oil evaporation is essentially complete and is an important basis for determining the stage of free oil evaporation.

[0193] By identifying the inflection point time and the corresponding evaporation porosity, the rapid evaporation stage can be defined solely based on the difference in evaporation rate, without needing to directly distinguish the specific fluid type within the pores. This clarifies the evaporation zone where free oil is located and provides reliable data for subsequent correction of clay adsorbed water interference and accurate calculation of free oil content.

[0194] In some embodiments, see Figure 5 As shown, by measuring the longitudinal relaxation spectrum of nuclear magnetic resonance of the target shale sample at different evaporation stages, the porosity distribution changes before evaporation and at multiple evaporation time points can be obtained. Figure 5The horizontal axis T2 represents the relaxation time, and the vertical axis represents the porosity component within a unit relaxation time interval. The figure shows the porosity distribution curves before evaporation, after 60 minutes of evaporation, after 2400 minutes of evaporation, and after 3120 minutes of evaporation.

[0195] like Figure 5 As shown, the porosity distribution curve before evaporation exhibits two main peaks, corresponding to the typical relaxation characteristics of adsorbed and free fluids in the shale sample, respectively. As evaporation proceeds for 60 minutes, the porosity component within the long relaxation time interval begins to decrease, indicating that the free fluid begins to escape from the sample pores.

[0196] After evaporation for 2400 minutes, the porosity component in the long relaxation time interval was significantly lower than the level before evaporation, indicating that the free fluid had been greatly reduced. In contrast, the porosity component in the short relaxation time interval decreased less, reflecting that the clay adsorbed water was still partially retained in the micro-nano pore structure.

[0197] When evaporation continued for 3120 minutes, the porosity component in the short relaxation time interval showed a slight decrease, indicating that a small amount of clay-adsorbed water began to desorb under continuous isothermal evaporation conditions. By comparing the relaxation spectra before evaporation and at 3120 minutes, the change in clay-adsorbed water can be quantitatively identified, providing data for subsequent correction of free oil evaporation interference.

[0198] based on Figure 5 Comparative analysis of relaxation spectra at different time points can effectively distinguish the response differences between free and adsorbed fluids during the evaporation process, enabling accurate identification of the changes in clay adsorbed water behavior, thus laying a reliable data foundation for the precise calculation of free oil content.

[0199] In some embodiments, see Figure 6 As shown, by measuring the nuclear magnetic resonance relaxation spectrum of the target shale sample at different stages of the evaporation test, the distribution of porosity components as a function of relaxation time can be obtained. Figure 6 In the figure, the horizontal axis T2 represents the relaxation time, and the vertical axis prosity represents the porosity component corresponding to the relaxation time interval. The curve reflects the response characteristics of different types of pore fluids in the pore structure of the sample.

[0200] like Figure 6 As shown, the relaxation spectrum before evaporation exhibits a main peak and a relatively long relaxation time region, characterizing the porosity contribution of free fluid and some weakly bound fluid in the sample. As the evaporation process progresses, the relaxation spectrum in the middle period shifts towards shorter relaxation times, and the peak intensity decreases significantly, indicating that evaporation gradually reduces the content of free fluid and results in a significant loss of mobile fluid within the pores.

[0201] As evaporation progresses, the porosity component corresponding to the long relaxation time interval continues to decrease, while the curve variation in the short relaxation time interval is relatively small. This indicates that confined fluids such as water adsorbed by clay maintain strong binding under evaporation conditions, undergoing only slight changes. Figure 6 By comparing the relaxation spectra at different evaporation times, the dynamic differences between free and adsorbed fluids during the evaporation process can be clearly seen.

[0202] Through the Figure 6 Analyzing the relaxation spectra at different time points can help identify the volume component changes of adsorbed water during evaporation and provide necessary data for subsequent correction of clay adsorbed water interference, thereby ensuring a more accurate calculation of free oil content.

[0203] In some embodiments, see Figure 7 As shown, by measuring the nuclear magnetic resonance relaxation spectra of the target shale sample at different evaporation stages, the change in porosity distribution with relaxation time during the evaporation process can be obtained. Figure 7 The horizontal axis T2 represents the relaxation time, and the vertical axis prosity represents the porosity component within the corresponding relaxation time interval. The figure shows the relaxation distribution curves before evaporation and at multiple evaporation times.

[0204] like Figure 7 As shown, the relaxation spectrum before evaporation exhibits a significant peak over a relatively long relaxation time range. This peak primarily corresponds to the free fluid contained within larger pores or highly interconnected pores in the pore structure. As evaporation proceeds, the peak value gradually decreases within the long relaxation time range, indicating that a large amount of free oil escapes during this stage, and the content of mobile fluid within the pores decreases significantly.

[0205] Meanwhile, the broad, gradual peak value appearing within the medium relaxation time range weakens significantly with increasing evaporation time, indicating that some weakly bound fluids also gradually decrease during continuous evaporation. In contrast, the signal variation within the shorter relaxation time range is relatively limited, suggesting that strongly bound fluids such as clay-adsorbed water remain relatively stable under isothermal evaporation conditions, undergoing only slight changes.

[0206] Through the Figure 7 By comparing the relaxation spectra at different evaporation stages, the response differences between free and adsorbed fluids during the evaporation process can be clearly distinguished. The spectral shifts and peak changes before and after evaporation can be used to identify the behavior of adsorbed water and provide effective quantitative basis for determining the evaporation stage of free oil, correcting for clay adsorbed water interference, and accurately calculating free oil content.

[0207] In some embodiments, see Figure 8 As shown, by recording the change in evaporation porosity of the target shale sample under isothermal evaporation conditions, the relationship curve between evaporation time and evaporation porosity can be obtained. Figure 8 The horizontal axis represents evaporation time in minutes; the vertical axis represents evaporation porosity in percentages; the points marked by triangles in the figure represent the evaporation porosity measurement results corresponding to different evaporation times.

[0208] like Figure 8 As shown, in the initial stage of evaporation, the evaporation porosity increases rapidly with evaporation time, and the curve shows a significant upward slope, indicating that the escape rate of the mobile fluid is high in the initial evaporation stage. As the evaporation time increases, the growth rate of evaporation porosity gradually decreases, the slope of the curve becomes gentler and eventually tends to stabilize, indicating that the main evaporating fluid type in this stage gradually transitions from easily evaporable fluids to difficult-to-evaporate or highly confined fluids.

[0209] exist Figure 8 In the graph, the inflection point of the curve is indicated by the trend line, and the corresponding evaporation time and evaporation porosity are marked by the vertical and horizontal arrows. This inflection point indicates a significant change in the evaporation rate and can be used to distinguish between the rapid evaporation stage and the subsequent slow evaporation stage of the free fluid. The evaporation rate is higher before the inflection point, reflecting that free oil is the main evaporating component; the evaporation rate slows down after the inflection point, reflecting the dominant role of bound fluid or adsorbed water in the evaporation process.

[0210] pass Figure 8 The trend of evaporation porosity variation shown can be used for segmented analysis of different evaporation stages to further determine the porosity range of the free oil evaporation stage, providing a basis for subsequent calculation of free oil content. Meanwhile, the stable segment of the curve reflects the final porosity level during the evaporation process, serving as an important reference for evaluating the integrity of the evaporation process and the degree of evaporation interference correction.

[0211] While this specification provides the steps of operation for the methods described in the embodiments or flowcharts, more or fewer steps may be included based on conventional or non-inventive means. The order of steps listed in the embodiments is merely one possible order of execution among many steps and does not represent the only possible order. In actual device or client product execution, the methods shown in the embodiments or drawings may be executed sequentially or in parallel (e.g., in a parallel processor or multi-threaded processing environment, or even a distributed data processing environment). The terms "comprising," "including," or any other variations thereof are intended to cover a non-exclusive inclusion, such that a process, method, product, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such a process, method, product, or apparatus. Without further limitations, the presence of other identical or equivalent elements in a process, method, product, or apparatus that includes said elements is not excluded. The terms "first," "second," etc., are used to denote names and do not indicate any particular order.

[0212] Those skilled in the art will also know that, besides implementing the controller using purely computer-readable program code, the same functions can be achieved by logically programming the method steps, making the controller function as logic gates, switches, application-specific integrated circuits (ASICs), programmable logic controllers (PLCs), and embedded microcontrollers. Therefore, such a controller can be considered a hardware component, and the devices within it used to implement various functions can also be considered structures within that hardware component. Alternatively, the devices used to implement various functions can be considered as both software modules implementing the method and structures within a hardware component.

[0213] As can be seen from the above description of the embodiments, those skilled in the art can clearly understand that this specification can be implemented by means of software plus necessary general-purpose hardware platforms. Based on this understanding, the technical solutions of this specification can essentially be embodied in the form of a software product. This computer software product can be stored in a storage medium, such as ROM / RAM, magnetic disk, optical disk, etc., and includes several instructions to cause a computer device (which may be a personal computer, mobile terminal, server, or network device, etc.) to execute the methods described in the various embodiments or some parts of the embodiments of this specification.

[0214] Although this specification has been described by way of examples, those skilled in the art will recognize that many variations and modifications are possible without departing from the spirit of this specification, and it is intended that the appended claims cover such variations and modifications without departing from the spirit of this specification.

Claims

1. A method for determining the free oil content in shale samples, characterized in that, include: A shale sample from the target area is obtained, and the fluid occurrence state recovery process is performed on the shale sample to obtain the target shale sample; The target shale sample was subjected to isothermal evaporation treatment, and sample mass data and nuclear magnetic resonance monitoring data were collected at multiple time points during the isothermal evaporation process; Based on the sample quality data and the nuclear magnetic resonance monitoring data, a time-porosity curve is constructed; and based on the time-porosity curve, the porosity change between each adjacent preset time point is calculated to determine the porosity change rate corresponding to each time period. The time period corresponding to the porosity change rate being greater than a preset rate threshold is defined as the target time period. Based on the evaporation porosity values ​​corresponding to multiple time points within the target time period, the porosity range of the free oil evaporation stage is determined. Extract the first nuclear magnetic resonance monitoring data at the start time and the second nuclear magnetic resonance monitoring data at the end time from the nuclear magnetic resonance monitoring data at the multiple time points, and calculate the change in clay adsorbed water content based on the first nuclear magnetic resonance monitoring data and the second nuclear magnetic resonance monitoring data; Based on the porosity change within the porosity range, determine the porosity increment corresponding to the free oil evaporation stage; The porosity increment is corrected based on the change in the water content adsorbed by the clay to obtain the corrected free oil porosity. The free oil content of the target shale sample is calculated based on the corrected free oil porosity and the volume of the target shale sample.

2. The method according to claim 1, characterized in that, The step of constructing a time-porosity curve based on the sample quality data and the nuclear magnetic resonance monitoring data includes: Based on the sample mass data, the changes in evaporation mass at multiple time points were determined; Based on the nuclear magnetic resonance monitoring data, the changes in pore response at multiple time points were determined; Based on the change in evaporation mass and the change in pore response, the evaporation porosity values ​​corresponding to multiple time points are determined; A time-porosity curve was constructed based on the evaporation time and the corresponding evaporation porosity value at multiple time points.

3. The method according to claim 1, characterized in that, The step of extracting first NMR monitoring data at the start time and second NMR monitoring data at the end time from the NMR monitoring data at the multiple time points, and calculating the change in clay adsorbed water content based on the first NMR monitoring data and the second NMR monitoring data, includes: Based on the first nuclear magnetic resonance monitoring data, the initial volume component of water adsorbed by clay was determined; Based on the second nuclear magnetic resonance monitoring data, the volume component of clay adsorbed water at each time point was determined; The change in clay adsorbed water content was determined based on the initial volume fraction of clay adsorbed water and the volume fraction of clay adsorbed water at each time point.

4. The method according to claim 1, characterized in that, The process of acquiring shale samples from the target area and performing fluid storage state recovery processing on the shale samples to obtain the target shale sample includes: Based on the formation pressure and formation temperature data of the target area, the acquired shale sample is subjected to corresponding pressure loading and temperature control treatment, so that the shale sample is maintained at the pressure and temperature for a preset duration, so that the pore fluid meets the preset storage requirements. Shale samples that meet the preset storage requirements are identified as the target shale samples.

5. The method according to claim 1, characterized in that, The method further includes: Based on the free oil content of the target shale sample and the preset oil content evaluation threshold, the fluidity evaluation level of the target shale sample in the reservoir is determined. Based on the aforementioned liquidity evaluation level, evaluation factors are generated for identifying sweet spots in shale oil reservoirs.

6. A device for determining the free oil content of shale samples, characterized in that, include: The sample determination module is used to acquire shale samples from the target area and perform fluid storage state recovery processing on the shale samples to obtain the target shale sample; The data determination module is used to perform isothermal evaporation treatment on the target shale sample and collect sample quality data and nuclear magnetic resonance monitoring data at multiple time points during the isothermal evaporation process. The interval determination module is used to construct a time-porosity curve based on the sample quality data and the nuclear magnetic resonance monitoring data; and to calculate the porosity change between each adjacent preset time point based on the time-porosity curve to determine the porosity change rate corresponding to each time period; to determine the time period corresponding to the porosity change rate being greater than a preset rate threshold as the target time period; and to determine the porosity interval of the free oil evaporation stage based on the evaporation porosity values ​​corresponding to multiple time points within the target time period. The change determination module is used to extract the first nuclear magnetic resonance monitoring data at the start time and the second nuclear magnetic resonance monitoring data at the end time from the nuclear magnetic resonance monitoring data at the multiple time points, and to calculate the change in clay adsorbed water content based on the first nuclear magnetic resonance monitoring data and the second nuclear magnetic resonance monitoring data. The free oil determination module is used to determine the porosity increment corresponding to the free oil evaporation stage based on the porosity change within the porosity range; to correct the porosity increment based on the change in clay adsorbed water content to obtain the corrected free oil porosity; and to calculate the free oil content of the target shale sample based on the corrected free oil porosity and the volume of the target shale sample.

7. An electronic device, characterized in that, It includes a processor and a memory for storing processor-executable instructions, wherein the processor, when executing the instructions, implements the steps of the method according to any one of claims 1 to 5.

8. A computer-readable storage medium, characterized in that, It stores computer instructions that, when executed by a processor, implement the steps of the method according to any one of claims 1 to 5.

Images