A method and system for correcting hydrocarbon content in shale oil and gas formations

Abstract

This invention provides a method and system for correcting hydrocarbon content in shale oil and gas formations. The method involves dividing the formation into sub-segments based on different core sampling intervals and collecting cores using both pressure-controlled closed core sampling and conventional core sampling methods. Pyrolysis is performed on the collected samples to obtain hydrocarbon content at different temperatures. The relationship curve between hydrocarbon content and total oil content in a single temperature range for pressure-controlled closed core sampling is used as the baseline hydrocarbon content relationship. The relationship curve between hydrocarbon content and total oil content in a single temperature range for conventional core sampling is used as the target hydrocarbon content relationship. The slope of the target hydrocarbon content relationship curve and the baseline hydrocarbon content relationship curve is analyzed to determine the hydrocarbon content requiring correction, and a correction coefficient is determined based on the slope. Therefore, a hydrocarbon content correction calculation model for conventional core sampling in different core segments is determined based on the correction coefficient. This scheme effectively overcomes the problems of high time and manpower consumption and insufficient data accuracy in existing hydrocarbon recovery technologies, achieving reliable hydrocarbon loss correction through simple operation.

Description

Technical Field

[0001] This invention relates to the field of resource exploration and development evaluation technology, and in particular to a method and system for correcting hydrocarbon content in shale oil and gas formations. Background Technology

[0002] Free hydrocarbons are one of the key parameters in the evaluation of shale oil resource potential. Light hydrocarbons, due to their low viscosity and good fluidity, make a significant contribution to improving the fluidity of free hydrocarbons, but they are unstable and easily lost through volatility. Therefore, the free hydrocarbon content measured by conventional experiments differs significantly from the true content due to the loss of light hydrocarbons. Moreover, the higher the maturity of the shale, the more severe the loss of free hydrocarbons, leading to inaccurate evaluation results of oil-bearing potential.

[0003] Currently, the industry generally adopts a method based on the light hydrocarbon loss curve (the correlation curve between light hydrocarbon content and time) to recover light hydrocarbon content. In addition, some technologies use crude oil chromatography and chloroform asphalt "A" chromatography to determine the light hydrocarbon recovery coefficient; some technologies use solvent extraction to extract the light hydrocarbon content from samples of different maturity stages and establish the light hydrocarbon recovery coefficient during the extraction process; some technologies use hydrocarbon generation kinetics methods to simulate the light hydrocarbon content at different maturity stages and obtain the light hydrocarbon recovery coefficient.

[0004] Most of these light hydrocarbon recovery methods do not consider the loss of light hydrocarbons during sample acquisition, and obtaining crude oil samples is largely a matter of chance. Furthermore, since each light hydrocarbon recovery method is only effective for the research sample, and each method requires a separate experimental procedure, consuming significant time and manpower to obtain the light hydrocarbon recovery coefficient, these methods are difficult to widely implement and apply.

[0005] The information disclosed in the background section of this invention is intended only to enhance the understanding of the general background of this invention, and should not be construed as an admission or in any way implying that such information constitutes prior art known to those skilled in the art. Summary of the Invention

[0006] To address the aforementioned problems, this invention provides a method for correcting hydrocarbon content in shale oil and gas formations. This method combines core acquisition techniques with in-situ closed-loop pyrolysis analysis of shale formations to correct hydrocarbon content in other core samples. It corrects the light hydrocarbon content of other core samples based on the light hydrocarbon content of the pressurized closed core sample, evaluating the light hydrocarbon loss caused by other core sampling methods. This method eliminates the phenomenon of hydrocarbon content loss in shale under normal surface temperature and pressure conditions, and can effectively correct for hydrocarbon losses caused by different core sampling methods under high underground temperature and pressure conditions. Preferably, in one embodiment, the method includes:

[0007] Distribution sampling step: For the target well, based on different coring intervals, the pressure-retaining closed coring intervals and ordinary coring intervals are divided according to set rules respectively, and core samples are collected by pressure-retaining closed coring and ordinary coring methods respectively;

[0008] Pyrolysis detection step: For the samples collected by different coring methods, weight sub-sampling and pyrolysis detection are carried out according to the matching standards respectively to obtain hydrocarbon content data at different detection temperatures;

[0009] Standard data extraction step: Select the hydrocarbon content data of the samples corresponding to the pressure-retaining closed coring method, and establish a correlation curve between the hydrocarbon content in a single temperature range and the total oil content as the reference hydrocarbon content relationship;

[0010] Data to be measured processing step: Based on the samples corresponding to the ordinary coring method, hydrocarbon content data are obtained respectively, and a correlation curve between the hydrocarbon content in a single temperature range and the total oil content is established as the hydrocarbon content relationship to be measured;

[0011] Calibration model determination step: Compare and analyze the curve slopes of different hydrocarbon content relationships to be measured and the reference hydrocarbon content relationship to determine whether calibration is required. If calibration is required, determine the calibration coefficient according to the curve slope, and determine the hydrocarbon content calibration operation model for the samples of the ordinary coring method according to the calibration coefficient;

[0012] Calibration execution step: For the well sections with calibration requirements, calculate the calibrated hydrocarbon content data based on the hydrocarbon content of the ordinary core samples using the matching hydrocarbon content calibration operation model.

[0013] Optionally, in one embodiment, in the distribution sampling step, for each divided coring interval, the pressure-retaining closed coring method is adopted in the 1 / 3 interval of the unit coring interval, and the ordinary coring method is adopted in the remaining intervals. The ordinary coring method includes the closed coring method and the conventional coring method.

[0014] Further, in one embodiment, in the pyrolysis detection step, the closed pyrolysis detection is carried out by continuously heating a sample to a set temperature range and maintaining a set time period. Among them, the hydrocarbon content data in the following experimental temperature ranges are obtained: temperature t = 0, 0 < t ≤ 90 °C, and 90 °C < t ≤ 300 °C, and the maintained time period is correspondingly matched according to different temperature ranges.

[0015] Preferably, in one embodiment, the method further includes:

[0016] Pressure-retaining closed sample pretreatment step: Before the pyrolysis detection step, after the core barrel using the pressure-retaining closed coring method reaches the surface, it is immediately placed in liquid nitrogen for freezing treatment for a set duration and then used as the sample for the pyrolysis detection step.

[0017] Optionally, in one embodiment, in the calibration model determination step, if the slope correlation value of the fitted curve between the hydrocarbon content to be measured and the quasi-hydrocarbon content relationship is greater than 0.05, then it is determined that the hydrocarbon content data to be measured needs to be calibrated.

[0018] Specifically, in a preferred embodiment, in the correction model determination step, the correction coefficient c is determined based on the curve slope according to the following formula:

[0019] c = k p / k s

[0020] In the formula, k p For the relevant slope corresponding to pressure-controlled closed-loop coring, k s This represents the slope corresponding to a closed-loop centering method.

[0021] Furthermore, in one embodiment, in the correction model determination step, the hydrocarbon content correction calculation model is determined as follows:

[0022] S'=S*c

[0023] In the formula, S is the hydrocarbon content measured in a sample obtained by a normal core sampling method with calibration requirements, c is the calibration coefficient of the corresponding core segment of the current sample, and S' is the corrected hydrocarbon content of the current core segment.

[0024] In a preferred embodiment, multiple blocks and various types of drilling segments are selected as target sample segments according to engineering correction requirements. The corresponding hydrocarbon content correction calculation models are determined to form a hydrocarbon content correction calculation model set. The block code, geological period parameters, rock maturity, and organic matter type corresponding to each hydrocarbon content correction calculation model are recorded and stored in association with the hydrocarbon content correction calculation model.

[0025] In an optional embodiment, during the correction execution step, a hydrocarbon content correction calculation model that meets the set conditions in terms of block code, geological period, rock maturity, and organic matter type of the drilling section to be tested is selected as the matching hydrocarbon content correction calculation model.

[0026] Based on other aspects of the methods described in any one or more of the foregoing embodiments, the present invention also provides a storage medium storing program code that can implement the methods described in any one or more of the foregoing embodiments.

[0027] Based on the application aspects of the methods described in any one or more of the above embodiments, the present invention also provides a hydrocarbon content correction system for shale oil and gas formations, which performs the methods described in any one or more of the above embodiments.

[0028] Compared with the closest prior art, the present invention also has the following beneficial effects:

[0029] This invention provides a method and system for correcting hydrocarbon content in shale oil and gas formations. The method involves dividing the formation into sub-segments based on different core sections and collecting core samples using both pressure-controlled closed core sampling and conventional core sampling methods. Hydrocarbon content is obtained at different detection temperatures through pyrolysis. The correlation curve between hydrocarbon content and total oil content in a single temperature range corresponding to the pressure-controlled closed core sampling method is used as a baseline hydrocarbon content relationship. The correlation curve between hydrocarbon content and total oil content in a single temperature range corresponding to the conventional core sampling method is used as the target hydrocarbon content relationship. By comparing and analyzing the slopes of the curves showing different target hydrocarbon contents and the baseline hydrocarbon content relationship, the hydrocarbon content requiring correction is determined, and correction coefficients are established based on the curve slopes. Therefore, a hydrocarbon content correction calculation model for conventional core sampling in different core sections is determined based on the correction coefficients, enabling hydrocarbon content correction and recovery calculations. This method can achieve hydrocarbon loss correction during oil and gas exploration, saving significant time and costs. Furthermore, it avoids the need for separate experimental design, saving substantial testing costs.

[0030] Furthermore, this scheme corrects the light hydrocarbon content of other core samples based on the light hydrocarbon content of the pressurized sealed core samples, and evaluates the light hydrocarbon loss caused by other core sampling methods. It can effectively make up for the shortcomings of traditional light hydrocarbon recovery methods that cannot accurately assess the light hydrocarbon loss during the core sampling stage. It helps to accurately evaluate the in-situ oil content of shale and can provide strong support for objectively assessing the in-situ gas-oil ratio and predicting the physical properties of formation fluids and formation pressure anomalies.

[0031] Other features and advantages of the invention will be set forth in the description which follows, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention may be realized and obtained by means of the structures particularly pointed out in the description, claims, and drawings. Attached Figure Description

[0032] The accompanying drawings are provided to further illustrate the invention and form part of the specification. They are used in conjunction with the embodiments of the invention to explain the invention and do not constitute a limitation thereof. In the drawings:

[0033] Figure 1 This is a schematic flowchart of a method for correcting hydrocarbon content in shale oil and gas formations provided in an embodiment of the present invention;

[0034] Figure 2 This is a schematic flowchart of a method for correcting hydrocarbon content in shale oil and gas formations provided in another embodiment of the present invention;

[0035] Figure 3 This is a coring method, layer distribution, and gas measurement curve diagram of a hydrocarbon content correction method for shale oil and gas formations provided in an embodiment of the present invention.

[0036] Figure 4The method for correcting hydrocarbon content in shale oil and gas formations provided in this embodiment of the invention includes pressurized sealed cores and sealed core S. g A comparative chart showing the relationship between the value and the total pyrolytic hydrocarbon content;

[0037] Figure 5 This is a comparison chart showing the relationship between the S0* value of pressurized closed cores and the total pyrolytic hydrocarbon content in the hydrocarbon content correction method for shale oil and gas formations provided in this embodiment of the invention.

[0038] Figure 6 This is a comparison diagram of the relationship between the S1 value of pressurized closed core and the total pyrolytic hydrocarbon content in the hydrocarbon content correction method for shale oil and gas formations provided in another embodiment of the present invention;

[0039] Figure 7 The corrected pressure-maintaining sealed core and sealed core S in the hydrocarbon content correction method for shale oil and gas formations provided in this embodiment of the invention. g A comparative chart showing the relationship between the value and the total pyrolytic hydrocarbon content;

[0040] Figure 8 This is a schematic diagram of the structure of the hydrocarbon content correction system for shale oil and gas formations provided in an embodiment of the present invention. Detailed Implementation

[0041] The embodiments of the present invention will be described in detail below with reference to the accompanying drawings and examples. Those skilled in the art will then fully understand how the present invention uses technical means to solve technical problems and achieve technical effects, and will be able to implement the present invention specifically based on the above-described implementation process. It should be noted that, as long as there is no conflict, the various embodiments and features of the present invention can be combined with each other, and the resulting technical solutions are all within the protection scope of the present invention.

[0042] Although the flowchart describes the operations as sequential processes, many of these operations can be performed in parallel, concurrently, or simultaneously. The order of the operations can be rearranged. A process can terminate when its operation is complete, but it may also have additional steps not included in the diagram. A process can correspond to a method, function, procedure, subroutine, subroutine, etc.

[0043] Computer equipment includes user equipment and network equipment. User equipment or clients include, but are not limited to, computers, smartphones, and PDAs (Personal Digital Assistants); network equipment includes, but is not limited to, a single network server, a server group consisting of multiple network servers, or a cloud based on cloud computing consisting of a large number of computers or network servers. Computer equipment can operate independently to implement this invention, or it can connect to a network and implement this invention through interaction with other computer devices within the network. The network in which the computer equipment resides includes, but is not limited to, the Internet, wide area networks (WANs), metropolitan area networks (MANs), local area networks (LANs), and VPN networks.

[0044] The terms “first,” “second,” etc., may be used herein to describe various units, but these units should not be limited by these terms; they are used merely to distinguish one unit from another. The term “and / or” as used herein includes any and all combinations of one or more of the associated listed items. When a unit is referred to as “connected” or “coupled” to another unit, it may be directly connected or coupled to said other unit, or there may be intermediate units present.

[0045] The terminology used herein is for the purpose of describing particular embodiments only and is not intended to limit the exemplary embodiments. Unless the context clearly indicates otherwise, the singular forms “a” and “an” as used herein are also intended to include the plural. It should also be understood that the terms “comprising” and / or “including” as used herein specify the presence of the stated features, integers, steps, operations, units, and / or components, without excluding the presence or addition of one or more other features, integers, steps, operations, units, components, and / or combinations thereof.

[0046] Free hydrocarbons are a key parameter in the evaluation of shale oil resource potential, generally characterized by the pyrolysis parameter S1. Light hydrocarbons (carbons and hydrogens prior to C10) contribute significantly to improving the flowability of free hydrocarbons due to their low viscosity and good fluidity; however, they are unstable and easily lost through volatility. Therefore, the free hydrocarbon content measured in conventional experiments differs considerably from the actual content due to the loss of light hydrocarbons. Furthermore, the higher the maturity of the shale, the more severe the loss of free hydrocarbons, leading to distorted oil-bearing potential evaluation results.

[0047] Currently, the industry generally adopts a method based on the light hydrocarbon loss curve (the correlation curve between light hydrocarbon content and time) to recover light hydrocarbon content. In addition, some technologies use crude oil chromatography and chloroform asphalt "A" chromatography to determine the light hydrocarbon recovery coefficient; some technologies use solvent extraction to extract the light hydrocarbon content from samples of different maturity stages and establish the light hydrocarbon recovery coefficient during the extraction process; some technologies use hydrocarbon generation kinetics methods to simulate the light hydrocarbon content at different maturity stages and obtain the light hydrocarbon recovery coefficient.

[0048] Most of these light hydrocarbon recovery methods do not consider the loss of light hydrocarbons during the acquisition of fresh samples, and obtaining crude oil samples is a matter of chance. Furthermore, since each light hydrocarbon recovery method is only effective for the research sample, and each method requires a separate experimental procedure, consuming significant time and manpower to obtain the light hydrocarbon recovery coefficient, these methods are difficult to widely implement and apply.

[0049] It is worth noting that the researchers of this invention found that during the core acquisition stage, when the sample undergoes the process of being pulled out of the drill bit, removed from the casing, and placed at room temperature, the rapid drop and release of temperature and pressure can lead to the precipitation and loss of a large amount of hydrocarbons. Most of the mobile hydrocarbons are volatilized during this stage, and the data shows that their loss can account for more than 90% of the total loss.

[0050] Based on this, the researchers of this invention propose that the light hydrocarbon content of fresh samples can be detected without loss first, and then the light hydrocarbon loss during the fresh sample acquisition process can be scientifically recovered using the content data without light hydrocarbon loss. This approach is of particular significance for research on light hydrocarbon loss and recovery in the field. Currently, in-situ closed-loop pyrolysis hydrocarbon detection can basically achieve lossless detection of light hydrocarbon content; combined with the analysis of rock samples obtained by different core acquisition methods, the light hydrocarbon loss during the core acquisition process can be reliably analyzed, thus providing strong support for the study of hydrocarbon content in oil and gas formations.

[0051] Closed-loop or conventional coring methods cannot maintain the internal pressure of the rock. Hydrocarbons are lost along with the pressure, and the degree of loss is influenced by a combination of factors, including coring time, formation pressure, and rock pore structure. Furthermore, once the core reaches the surface, it is exposed to the atmosphere, leading to continuous hydrocarbon loss. High-pressure and low-pressure losses of hydrocarbons during coring exhibit different characteristics: under high pressure, they are lost through rapid seepage, while under low pressure, they are lost through slow diffusion. Using the loss patterns observed under low-pressure conditions to estimate high-pressure seepage losses during coring is clearly unscientific, thus causing significant errors in the estimation of in-situ oil content.

[0052] To address the aforementioned problems, this invention provides a method and system for correcting hydrocarbon content in shale oil and gas formations. The method corrects the light hydrocarbon content of rocks based on in-situ closed-loop pyrolytic hydrocarbon detection data from different core sampling methods. By detecting the light hydrocarbon content of core samples obtained through closed-loop pyrolytic core sampling at the drilling site, the original light hydrocarbon content under the given conditions is obtained and used as the true light hydrocarbon content of the formation. The same closed-loop pyrolytic hydrocarbon content detection is then performed on core samples obtained through other core sampling methods. The light hydrocarbon content of other core samples is corrected based on the light hydrocarbon content of the closed-loop core samples, thus evaluating the light hydrocarbon loss caused by other core sampling methods. This method effectively compensates for the deficiency of traditional light hydrocarbon recovery methods in accurately assessing light hydrocarbon loss during the core sampling stage, and has important reference value for shale oil resource evaluation.

[0053] The following describes the detailed flow of the method according to an embodiment of the present invention with reference to the accompanying drawings, the steps of which can be executed in a computer system containing, for example, a set of computer-executable instructions. Although the logical order of the steps is shown in the flowchart, in some cases, the steps shown or described may be performed in a different order than that shown here.

[0054] Example 1:

[0055] Figure 1 This diagram illustrates a flow chart of the hydrocarbon content correction method for shale oil and gas formations provided in Embodiment 1 of the present invention. Figure 1 As can be seen, the method includes the following steps.

[0056] Distribution sampling steps: Based on different coring sections of the target well, pressure-sealed coring sections and ordinary coring sections are divided according to the set rules, and core samples are collected by pressure-sealed coring and ordinary coring methods respectively;

[0057] Pyroelectric detection steps: For samples collected by different core sampling methods, weighing, sampling, and pyroelectric detection are performed according to matching standards to obtain hydrocarbon content data at different detection temperatures;

[0058] Standard data extraction steps: Select hydrocarbon content data of samples corresponding to the pressure-sealed core sampling method, establish the correlation curve between hydrocarbon content and total oil content in a single temperature range, and use it as the standard hydrocarbon content relationship.

[0059] Data processing steps: Based on the ordinary core sampling method, hydrocarbon content data are obtained for each sample, and a correlation curve between hydrocarbon content and total oil content in a single temperature range is established as the relationship of hydrocarbon content to be tested;

[0060] The steps for determining the calibration model are as follows: Compare and analyze the slopes of the curves showing the relationship between different hydrocarbon contents to be measured and the standard hydrocarbon content relationship to determine whether calibration is required. If calibration is required, determine the calibration coefficient based on the curve slope, and determine the hydrocarbon content calibration calculation model for samples taken using the ordinary core sampling method based on the calibration coefficient.

[0061] Correction execution steps: For drilling sections that require correction, the corrected hydrocarbon content data is calculated using a matched hydrocarbon content correction calculation model based on the hydrocarbon content of ordinary core samples.

[0062] Within the same stratigraphic unit, the gas content in closed-loop or conventional-loop cored sections is high, while the gas content in pressurized closed-loop cored sections is low, and significantly lower than that in closed-loop or conventional-loop cored sections. In other words, the degree of light hydrocarbon loss is closely related to the cored method, and the cored method has a direct impact on the gas content; pressurized closed-loop cored sections can effectively retain more light hydrocarbons.

[0063] The rock light hydrocarbon content correction implemented in the above embodiments of the present invention is based on the on-site sealed thermal hydrocarbon release detection data of different coring methods. By detecting the sealed thermal hydrocarbon release content of the core samples obtained by the pressure-maintained sealed coring method at the drilling site, the light hydrocarbon content under the original conditions is obtained as the standard hydrocarbon content of the rock formation. The same sealed thermal hydrocarbon release content detection is carried out on the core samples obtained by other coring methods to obtain hydrocarbon content data. The light hydrocarbon content of other core samples is corrected according to the light hydrocarbon content of the pressure-maintained sealed core samples, and the light hydrocarbon loss caused by other coring methods is analyzed. This method can effectively overcome the defect that the traditional light hydrocarbon recovery method cannot accurately evaluate the light hydrocarbon loss during the coring stage and achieve the precise study of the light hydrocarbon content of the rock formation.

[0064] Preferably, in one embodiment, in the distributed sampling step, for each coring interval divided, the pressure-maintained sealed coring method is adopted in the 1 / 3 coring interval of the unit coring interval, and the remaining part of the interval adopts the ordinary coring method, and the ordinary coring method includes the sealed coring method and the conventional coring method. In actual application, samples are taken at an interval of one meter, and a sample is collected every one-meter interval of the well depth.

[0065] Among them, the division of the coring intervals is determined by the decision-making of the oilfield drilling design principle and is not restricted by on-site experiments. Based on this, the subsequent on-site experimental work is naturally carried out under the conditions of the drilling design principle. In actual application, the drilling design principle is determined according to regional seismic and adjacent well data. The specific method for determining the drilling design principle can be realized by those skilled in the art using a feasible scheme in the field according to the conditions of the drilling site, and the present invention does not specifically limit it.

[0066] Further, in one embodiment, in the thermal release detection step, for the samples collected by different coring methods, weighing and sub-sampling and thermal release detection are respectively carried out according to the matching standards to obtain the hydrocarbon content data at different detection temperatures.

[0067] Specifically, in an optional embodiment, in the thermal release detection step, the sealed thermal release detection is carried out by continuously heating a sample to a set temperature range and maintaining a set time period. Among them, the hydrocarbon content data in the following experimental temperature ranges are obtained: temperature t = 0, 0 < t ≤ 90°C, and 90°C < t ≤ 300°C, and the maintained time period is correspondingly matched according to different temperature ranges. <​​​Heat to 90 degrees Celsius and hold for 3 minutes to test S0*, then heat to 300 degrees Celsius and hold for 12 minutes to test S1. The heating rate is 50 degrees Celsius / minute.

[0069] Based on this, S was obtained through closed-loop pyroelectric detection and analysis. g The three pyroelectric peaks S0* and S1, S g The peaks are dominated by C1-C5 gaseous hydrocarbons, the S0* peak is dominated by C6-C10 light hydrocarbons, and the S1 peak is dominated by C10+ hydrocarbons; Total = S g +S0*+S1 represents the total amount of hydrocarbons released by heat.

[0070] In practical applications, the in-situ closed-system pyroelectric detection and analysis method places the sample in a closed system to detect the hydrocarbons released from the sample, avoiding the problem of hydrocarbon loss due to contact with the atmospheric environment. In-situ closed-system pyroelectric analysis detects the hydrocarbon content released from rocks at ≤300℃, which is generally considered to be the free oil content. Combined with pressure-controlled closed coring, sampling is performed from the center of a pressure-controlled, sealed core after liquid nitrogen freezing, providing accurate information on the formation's oil content. Core samples obtained through conventional coring methods are then weighed and analyzed according to the requirements of pyroelectric detection to obtain hydrocarbon content information at different temperatures.

[0071] Furthermore, the standard data extraction steps were performed, and the hydrocarbon content data of the samples corresponding to the pressure-sealed core sampling method were selected. The correlation curve between the hydrocarbon content and the total oil content in a single temperature range was established as the standard hydrocarbon content relationship.

[0072] Perform the data processing steps, obtain hydrocarbon content data for each sample based on the ordinary core sampling method, and establish the correlation curve between hydrocarbon content and total oil content in a single temperature range as the relationship of hydrocarbon content to be measured.

[0073] Next, hydrocarbon content data from pressurized sealed cores and cores obtained through other sampling methods are compared. Using the hydrocarbon content of pressurized sealed cores as a benchmark, correction coefficients are determined based on the slope of the correlation curve between hydrocarbon content and total oil content within a single temperature range. This correction is then applied to hydrocarbon content data from cores obtained through other sampling methods to obtain accurate formation hydrocarbon content information. Based on this, the correction model determination step is executed. The slopes of the curves showing different hydrocarbon content relationships to be measured versus the benchmark hydrocarbon content relationship are compared and analyzed to determine if correction is necessary. If correction is required, correction coefficients are determined based on the curve slopes.

[0074] Preferably, in one embodiment, in the calibration model determination step, if the slope correlation value of the fitting curve between the measured hydrocarbon content relationship and the quasi-parameter hydrocarbon content relationship is greater than 0.05, then it is determined that the measured hydrocarbon content data needs to be calibrated; the slope correlation value is the absolute value of the difference between the slopes of the two fitting curves, i.e., |k p -k s|

[0075] Specifically, in an optional embodiment, in the correction model determination step, the correction coefficient c is determined based on the curve slope according to the following formula:

[0076] c = k p / k s In the formula, k p For the relevant slope corresponding to pressure-controlled closed-loop coring, k s This represents the slope corresponding to a closed-loop centering method.

[0077] Further, a correction execution step is performed, in which a hydrocarbon content correction calculation model for samples obtained by ordinary coring is determined based on the correction model. This model is used to calculate the corrected hydrocarbon content data based on the hydrocarbon content of ordinary coring samples for matching drilling intervals that require correction.

[0078] Specifically, in an optional embodiment, the hydrocarbon content correction calculation model is determined as follows in the correction model determination step:

[0079] S'=S*c

[0080] In the formula, S is the hydrocarbon content measured in a sample obtained by a normal core sampling method with calibration requirements, c is the calibration coefficient of the corresponding core segment of the current sample, and S' is the corrected hydrocarbon content of the current core segment.

[0081] In practical applications, multiple blocks and various types of drilling segments can be selected as target sample segments according to the correction application requirements in the project. The corresponding hydrocarbon content correction calculation models can be determined according to the operations in the above embodiments of the present invention, thus forming a set of hydrocarbon content correction calculation models for diversified correction application requirements.

[0082] Record the block code, geological period parameters, rock maturity, and organic matter type corresponding to each hydrocarbon content correction calculation model, and store them in association with the hydrocarbon content correction calculation model; in an optional embodiment, the block code and geological period are used as indexes to realize storage, which is convenient for retrieval and calling in subsequent applications.

[0083] Therefore, based on the established hydrocarbon content correction calculation model, when the drilling section to be tested has a hydrocarbon content analysis requirement in actual application, sampling and testing can be carried out by using ordinary coring methods, and the hydrocarbon content results that conform to the actual situation of the drilling section can be calculated based on the hydrocarbon content data obtained by the hydrocarbon content correction calculation model determined in this embodiment of the invention.

[0084] In practical applications, a hydrocarbon content correction calculation model is first selected based on the block code and geological period of the drilling interval to be tested. Then, from the selected one or more hydrocarbon content correction calculation models, the hydrocarbon content correction calculation model that meets the set conditions in terms of stratum maturity and organic matter type is determined. This model is then used as the matching hydrocarbon content correction calculation model for the current drilling interval to be tested.

[0085] Then, after sampling and testing the current drilling section using ordinary coring methods, a matching hydrocarbon content correction calculation model is used to perform correction calculations to obtain hydrocarbon content results that match the actual situation of the drilling section.

[0086] Generally, strata from the same geological period within the same sedimentary basin block that share similar lithology, maturity, and organic matter type can be used for lateral drilling applications. Specifically, the lithology of drilling strata can be determined based on rock and mineral composition, rock maturity is usually expressed using vitrinite reflectance, and organic matter type is typically determined based on kerogen type and microstructure composition.

[0087] On the other hand, if no matching hydrocarbon content correction calculation model is identified for the current drilling interval to be tested, it can be used as a sample drilling interval. The distribution sampling step, pyroelectric detection step, standard data extraction step, test data processing step, and correction model determination step are performed according to the method of the embodiment of the present invention to determine the corresponding correction coefficient, thereby obtaining the corresponding hydrocarbon content correction calculation model and storing it in the hydrocarbon content correction calculation model set. This enriches the model data of the hydrocarbon content correction calculation model set and provides more comprehensive model support for subsequent applications.

[0088] The hydrocarbon content correction method for shale oil and gas formations provided in this invention, combined with the core acquisition method and the in-situ closed-loop pyrolysis analysis method for shale formations, not only eliminates the loss of shale hydrocarbon content under normal surface temperature and pressure conditions, but also effectively corrects the hydrocarbon loss caused by different core acquisition methods under underground high temperature and pressure conditions.

[0089] Applying the solution of this invention has at least the following beneficial effects:

[0090] (1) Hydrocarbon loss correction can be achieved during the oil and gas exploration process. The hydrocarbon loss correction process is included in the drilling, coring and field testing process, which saves a lot of time and costs, avoids the need to design experiments separately, and saves a lot of testing costs.

[0091] (2) Considering the hydrocarbon loss behavior during the storage of the quasi-rod sample, the hydrocarbon loss during the core sampling process is corrected based on the accurate quasi-rod data. The corrected data represents the in-situ oil content under formation conditions, which is closer to the true value. This method not only helps to accurately evaluate the in-situ oil content of shale, but also provides strong support for objectively assessing the in-situ gas-oil ratio and predicting the physical properties of formation fluids and formation pressure anomalies.

[0092] Example 2:

[0093] Figure 2 This diagram illustrates a flow chart of the hydrocarbon content correction method for shale oil and gas formations provided in Embodiment 2 of the present invention. Figure 2 As can be seen, the method includes the following steps.

[0094] Distribution sampling steps: Based on different coring sections of the target well, pressure-sealed coring sections and ordinary coring sections are divided according to the set rules, and core samples are collected by pressure-sealed coring and ordinary coring methods respectively;

[0095] Pyroelectric detection steps: For samples collected by different core sampling methods, weighing, sampling, and pyroelectric detection are performed according to matching standards to obtain hydrocarbon content data at different detection temperatures;

[0096] Standard data extraction steps: Select hydrocarbon content data of samples corresponding to the pressure-sealed core sampling method, establish the correlation curve between hydrocarbon content and total oil content in a single temperature range, and use it as the standard hydrocarbon content relationship;

[0097] Data processing steps: Based on the ordinary core sampling method, hydrocarbon content data are obtained for each sample, and a correlation curve between hydrocarbon content and total oil content in a single temperature range is established as the relationship of hydrocarbon content to be tested;

[0098] The steps for determining the calibration model are as follows: Compare and analyze the slopes of the curves showing the relationship between different analyte hydrocarbon contents and the standard hydrocarbon content relationship to determine whether calibration is required. If calibration is required, determine the calibration coefficient based on the curve slope, and determine the hydrocarbon content calibration calculation model for samples obtained by ordinary core sampling based on the calibration model described above.

[0099] Correction execution steps: For drilling sections requiring correction, the corrected hydrocarbon content data is calculated using a matched hydrocarbon content correction calculation model based on the hydrocarbon content of ordinary core samples. Example 2 is a variation of Example 1; therefore, steps identical or similar to those in Example 1 will not be repeated, only the distinguishing steps will be explained.

[0100] Furthermore, in a preferred embodiment, the method further includes:

[0101] Pretreatment steps for pressure-sealed samples: Before the pyroelectric detection step, the rock sample core tube, which is obtained by pressure-sealed core sampling, is immediately placed in liquid nitrogen for a set time after reaching the surface, and then used as the sample for the pyroelectric detection step.

[0102] In the field exploration of shale oil, considering the loss of light hydrocarbons, the pressure-sealed core sampling method is receiving increasing attention. In order to obtain true oil-bearing information of the formation, oil and gas explorers use the pressure-sealed method to retrieve the core to the surface, and then use liquid nitrogen to freeze the entire pressure-sealed core cylinder (with the core sealed) for more than 4 hours. This can effectively prevent the loss of light hydrocarbons from volatilization in the core and ensure that the hydrocarbon content data obtained by pyrolysis detection of samples collected based on the pressure-sealed core sampling method is consistent with the true hydrocarbon content data to the greatest extent.

[0103] The present invention will be further described below with reference to specific embodiments. The scope of the present invention is not limited to the embodiments, but is defined in the claims.

[0104] The following analysis will take the core section of the Qingshankou Formation shale from a shale oil exploration well in the Songliao Basin as an example.

[0105] The core sampling interval for the Qingshankou Formation shale in this well is 217 meters, of which 74 meters were cored using pressure-controlled closed-loop core sampling, and the remaining 143 meters were cored using closed-loop core sampling. In this implementation case, both pressure-controlled closed-loop core sampling and closed-loop core sampling were used in the core sampling interval, with the two methods implemented alternately.

[0106] Figure 3 The distribution of coring methods and gas measurement curves are shown. The gas measurement concentration can reflect the lost hydrocarbons. It can be clearly seen from the figure that the gas measurement value of the pressure-maintained closed coring section is much lower than that of the closed coring section.

[0107] After the pressure-sealed core sampler reaches the ground, it is placed in liquid nitrogen and frozen for 4 hours before being opened for sampling.

[0108] In practical applications, samples are taken at 1-meter intervals for closed-loop pyroelectric analysis.

[0109] Closed-loop pyrolysis analysis can be performed according to the scheme in the literature (Evaluation of oil-bearing characteristics of shale by closed-loop pyrolysis method - taking the Daanzhai section of the Jurassic in Sichuan Basin as an example, Petroleum Experimental Geology, Luo Chao, Zhang Huanxu et al.).

[0110] S was obtained by closed-loop pyrolysis. g The three pyroelectric peaks S0* and S1, S g The peaks are dominated by C1-C5 gaseous hydrocarbons, the S0* peak is dominated by C6-C10 light hydrocarbons, and the S1 peak is dominated by C10+ hydrocarbons. In actual detection, the hydrocarbon content at different temperature ranges can be obtained by continuously heating a single sample. For example, in one embodiment, the S content can be tested without heating for 3 minutes.g Heat to 90 degrees Celsius and hold for 3 minutes to test S0*, then heat to 300 degrees Celsius and hold for 12 minutes to test S1. The heating rate is 50 degrees Celsius / minute.

[0111] Once the sealed core sample reaches the ground, it is taken for sealed pyrolysis analysis under the same conditions to obtain the same parameters. Total = S g +S0*+S1 represents the total amount of hydrocarbons released by heat.

[0112] Figure 4 , Figure 5 and Figure 6 These represent pressurized sealed core and sealed core S, respectively. g The correlation between the content of each single type of hydrocarbon in S0* and S1 and the total pyrolytic hydrocarbon content (oil content); Figure 4 For example, in the graph, the vertical axis represents Sg, i.e., the content of gaseous hydrocarbons, and the horizontal axis represents the total oil content. Total oil content = Sg g +S0*+S1.

[0113] from Figure 5 and Figure 6 It can be seen that the S0* and S1 data of both pressurized and sealed cores are closely intertwined, and the slopes of the correlation curves with the total pyrolytic hydrocarbon content are very similar. This indicates that both pressurized and sealed core sampling methods effectively preserve the S0* and S1 data in the samples, and the two methods show good consistency. This suggests that the S0* and S1 data for the current layer in this implementation case do not require correction. However, in practical applications, there may be situations where the S0* and S1 data require correction.

[0114] Figure 4 Clearly reflects the pressure-retaining and sealed core S g Greater than the sealed core S g The values ​​and the slopes of the correlation curves between the two and the total pyrolytic hydrocarbon content differ by nearly 100%, indicating that the closed-loop core sampling method caused the loss of gaseous hydrocarbons.

[0115] The correction factor is determined to be 1.78 based on the slope. Figure 7 S was shown g The relationship between the corrected value and the total pyrolytic hydrocarbon content, and the S values ​​for different core sampling methods. g They are tightly intertwined, indicating that after correction S g The values ​​are in good agreement with the actual hydrocarbon content data.

[0116] The formula for calculating the correction factor can be expressed as:

[0117] c = k p / k s

[0118] In the formula, k p For the relevant slope corresponding to pressure-controlled closed-loop coring, ks This represents the slope corresponding to a closed-loop centering method.

[0119] Furthermore, the corrected data S' is calculated based on the correction factor c according to the following formula:

[0120] S'=S*c

[0121] In the formula, S is the hydrocarbon content measured in a sample obtained by a normal core sampling method with calibration requirements, c is the calibration coefficient of the corresponding core segment of the current sample, and S' is the corrected hydrocarbon content of the current core segment.

[0122] For the foregoing method embodiments, in order to simplify the description, they are all described as a series of actions. However, those skilled in the art should understand that the present invention is not limited to the described order of actions, because according to the present invention, some steps can be performed in other orders or simultaneously. Furthermore, those skilled in the art should also understand that the embodiments described in the specification are preferred embodiments, and the actions and modules involved are not necessarily essential to the present invention.

[0123] It should be noted that, in other embodiments of the present invention, the method can also combine one or more of the above embodiments to obtain a new method for correcting hydrocarbon content in shale oil and gas formations, so as to achieve accurate research on the true hydrocarbon content data of oil and gas formations.

[0124] It should be noted that, based on the methods in any one or more embodiments of the present invention described above, the present invention also provides a storage medium storing program code that can implement the methods described in any one or more embodiments. When the program code is executed by the operating system, it can implement the hydrocarbon content correction method for shale oil and gas formations as described above.

[0125] Example 3:

[0126] The methods described in the above-disclosed embodiments of the present invention are detailed. These methods can be implemented using various forms of devices or systems. Therefore, based on other aspects of the methods described in any one or more of the above embodiments, the present invention also provides a hydrocarbon content correction system for shale oil and gas formations. This system is used to execute the hydrocarbon content correction method for shale oil and gas formations described in any one or more of the above embodiments. Specific embodiments are given below for detailed description.

[0127] Specifically, Figure 8 The diagram shows a schematic representation of the structure of a hydrocarbon content correction system for shale oil and gas formations provided in an embodiment of the present invention. Figure 8 As shown, the system includes:

[0128] A distribution sampling module configured to divide a pressure-retaining closed coring section and a normal coring section according to set rules for different coring intervals of a target well, and collect core samples by using pressure-retaining closed coring and normal coring methods respectively;

[0129] A pyroanalysis detection module configured to perform weighing and sub-sampling and pyroanalysis detection on samples collected by different coring methods according to matching standards respectively, and obtain hydrocarbon content data at different detection temperatures;

[0130] A standard data extraction module configured to select the hydrocarbon content data of the samples corresponding to the pressure-retaining closed coring method, establish a correlation curve between the hydrocarbon content in a single temperature range and the total oil content thereof, and use it as a criterion hydrocarbon content relationship;

[0131] A data to be measured processing module configured to obtain hydrocarbon content data based on the samples corresponding to the normal coring method respectively, establish a correlation curve between the hydrocarbon content in a single temperature range and the total oil content thereof, and use it as a hydrocarbon content relationship to be measured;

[0132] A correction model determination module configured to compare and analyze the curve slopes of different hydrocarbon content relationships to be measured and the criterion hydrocarbon content relationship, determine whether correction is needed, if correction is needed, determine a correction coefficient according to the curve slope, and determine a hydrocarbon content correction operation model for the samples of the normal coring method according to the correction coefficient;

[0133] A correction execution module configured to calculate corrected hydrocarbon content data based on the hydrocarbon content of normal coring samples by using a matching hydrocarbon content correction operation model for the well sections with correction requirements.

[0134] Optionally, in one embodiment, the distribution sampling module is configured to: for each divided coring interval, use the pressure-retaining closed coring method in the 1 / 3 section of the unit coring interval, and use the normal coring method for the remaining sections, and the normal coring method includes a closed coring method and a conventional coring method.

[0135] Further, in one embodiment, the pyroanalysis detection module performs closed pyroanalysis detection by continuously heating a sample to a set temperature range and maintaining a set time period, and obtains hydrocarbon content data in the following experimental temperature ranges: temperature t = 0, 0 < t ≤ 90°C, and 90°C < t ≤ 300°C, and the maintained time period is set according to different temperature ranges.

[0136] Preferably, in one embodiment, the system further includes:

[0137] A pressure-retaining closed sample pretreatment module configured to, before performing pyroanalysis detection, immediately place the core barrel using the pressure-retaining closed coring method in liquid nitrogen for freezing treatment for a set duration after reaching the surface, and then use it as a sample for the pyroanalysis detection module to perform pyroanalysis detection.

[0138] Optionally, in one embodiment, the correction model determination module is configured to: if the slope correlation value of the fitting curve between the measured hydrocarbon content relationship and the quasi-rod hydrocarbon content relationship is greater than 0.05, then determine that the measured hydrocarbon content data needs to be corrected.

[0139] Specifically, in a preferred embodiment, the correction model determination module determines the correction coefficient c based on the curve slope according to the following formula:

[0140] c = k p / k s

[0141] In the formula, k p For the relevant slope corresponding to pressure-controlled closed-loop coring, k s This represents the slope corresponding to a closed-loop centering method.

[0142] Furthermore, in one embodiment, the correction model determination module determines the hydrocarbon content correction calculation model as follows:

[0143] S'=S*c

[0144] In the formula, S is the hydrocarbon content measured in a sample obtained by a normal core sampling method with calibration requirements, c is the calibration coefficient of the corresponding core segment of the current sample, and S' is the corrected hydrocarbon content of the current core segment.

[0145] In practical applications, in the preferred embodiment, multiple blocks and various types of drilling segments are selected as target sample segments according to engineering correction requirements. The corresponding hydrocarbon content correction calculation models are determined to form a hydrocarbon content correction calculation model set. The block code, geological period parameters, rock maturity, and organic matter type corresponding to each hydrocarbon content correction calculation model are recorded and stored in association with the hydrocarbon content correction calculation model.

[0146] In an optional embodiment, the correction execution module is configured to select a hydrocarbon content correction calculation model that meets the set conditions for the block code, geological period, rock maturity and organic matter type of the drilling section to be tested, as the matching hydrocarbon content correction calculation model.

[0147] In the hydrocarbon content correction system for shale oil and gas formations provided in this embodiment of the invention, each module or unit structure can operate independently or in combination according to actual sample processing and detection calculation requirements to achieve the corresponding technical effects.

[0148] It should be understood that the embodiments disclosed herein are not limited to the specific structures, processing steps, or materials disclosed herein, but should be extended to equivalent substitutions of these features as understood by those skilled in the art. It should also be understood that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting.

[0149] The phrase "an embodiment" in the specification means that a specific feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment of the invention. Therefore, the phrase "an embodiment" appearing in various places throughout the specification does not necessarily refer to the same embodiment.

[0150] While the embodiments disclosed in this invention are as described above, the content is merely for the purpose of facilitating understanding of the invention and is not intended to limit the invention. Any person skilled in the art to which this invention pertains may make any modifications and variations in form and detail of the implementation without departing from the spirit and scope disclosed herein; however, the scope of patent protection for this invention shall still be determined by the scope defined in the appended claims.

Claims

1. A method for correcting hydrocarbon content in shale oil and gas formations, characterized in that, The method includes: Distribution sampling step: Based on different coring intervals of the target well, the pressure-retaining closed coring intervals and ordinary coring intervals are divided according to set rules respectively, and core samples are collected by pressure-retaining closed coring and ordinary coring methods respectively; Thermal release detection step: For the samples collected by different coring methods, weight sub-sampling and thermal release detection are carried out according to the matching standards respectively to obtain the hydrocarbon content data at different detection temperatures; Standard data extraction step: Select the hydrocarbon content data of the samples corresponding to the pressure-retaining closed coring method, and establish a correlation curve between the hydrocarbon content in a single temperature range and the total oil content as the reference hydrocarbon content relationship; Data to be measured processing step: Based on the samples corresponding to the ordinary coring method, hydrocarbon content data are obtained respectively, and a correlation curve between the hydrocarbon content in a single temperature range and the total oil content is established as the hydrocarbon content relationship to be measured; Calibration model determination step: Compare and analyze the curve slopes of different hydrocarbon content relationships to be measured and the reference hydrocarbon content relationship, determine whether calibration is required, if calibration is required, determine the calibration coefficient according to the curve slope, and determine the hydrocarbon content calibration operation model for the samples of the ordinary coring method according to the calibration coefficient; Calibration execution step: For the well sections with calibration requirements, calculate the calibrated hydrocarbon content data based on the hydrocarbon content of the ordinary core samples using the matching hydrocarbon content calibration operation model.

2. The method according to claim 1, characterized in that, In the distribution sampling step, for each divided coring interval, the pressure-retaining closed coring method is used in the 1 / 3 interval of the unit coring interval, and the ordinary coring method is used in the remaining intervals. The ordinary coring method includes the closed coring method and the conventional coring method.

3. The method according to claim 1, characterized in that, In the thermal release detection step, the closed thermal release detection is carried out by continuously heating a sample to a set temperature range and maintaining a set time period. Among them, the hydrocarbon content data in the following experimental temperature ranges are obtained: temperature t = 0, 0 < t ≤ 90 °C, and 90 °C < t ≤ 300 °C, and the maintained time period is set according to different temperature ranges.

4. The method according to claim 1, characterized in that, The method further includes: Pressure-retaining closed sample pretreatment step: Before the thermal release detection step, after the coring barrel using the pressure-retaining closed coring method reaches the surface, it is immediately placed in liquid nitrogen for freezing treatment for a set duration, and then used as the sample for the thermal release detection step.

5. The method according to claim 1, characterized in that, In the calibration model determination step, if the correlation value of the curve slope of the hydrocarbon content relationship to be measured and the reference hydrocarbon content relationship fitting curve is greater than 0.05, it is determined that the hydrocarbon content data to be measured needs calibration.

6. The method according to claim 1, characterized in that, In the calibration model determination step, the calibration coefficient c is determined according to the following formula based on the curve slope: c=k p / k s The hydrocarbon content calibration operation model is determined according to the calibration coefficient as follows: S’ = S * c In the formula, k p For the relevant slope corresponding to pressure-controlled closed-loop coring, k s S is the slope corresponding to closed coring; S is the hydrocarbon content measured in a sample obtained by ordinary coring with calibration requirements; c is the calibration coefficient of the coring segment corresponding to the current sample; and S' is the corrected hydrocarbon content of the current coring segment.

7. The method according to claim 1, characterized in that, According to the engineering calibration requirements, multiple well sections of various types in multiple blocks are selected as the target sample sections respectively, and the corresponding hydrocarbon content calibration operation models are determined respectively to form a hydrocarbon content calibration operation model set. Record the block code, geological period parameters, rock maturity, and organic matter type corresponding to each hydrocarbon content calibration operation model, and store them in association with the hydrocarbon content calibration operation model.

8. The method according to claim 1, characterized in that, In the calibration execution step, a hydrocarbon content calibration calculation model that meets the set conditions in terms of block code, geological period, rock maturity and organic matter type of the drilling section to be tested is selected as the matching hydrocarbon content calibration calculation model.

9. A storage medium, characterized in that, The storage medium stores program code that can implement the method as described in any one of claims 1 to 8.

10. A hydrocarbon content correction system for shale oil and gas formations, characterized in that, The system performs the method as described in any one of claims 1 to 8.

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