A method for identifying the manner in which hydrocarbons are lost through a cap rock

Abstract

The application discloses a method for identifying the dispersion mode of oil and gas through a cap layer, and relates to the technical field of oil and gas reservoirs. The technical scheme is as follows: selecting a rock sample, carrying out particle fluorescence testing, and obtaining a parameter QGF-E representing the content of hydrocarbon adsorbed on the outside of a mineral particle and a parameter QGF-index representing the content of hydrocarbon in the inside of the mineral particle; identifying the dispersion mode of oil and gas through the cap layer according to the relationship between QGF-E and QGF-index, wherein if QGF-E is positively correlated with QGF-index, it indicates that the dispersion mode of oil and gas through the cap layer is slow percolation; and if QGF-index basically remains unchanged with the increase of QGF-E, it indicates that the dispersion mode of oil and gas through the cap layer is episodic rupture. The analysis and testing data obtained through the quantitative fluorescence testing of the cap layer are used to distinguish the dispersion mode of oil and gas through the cap layer by using the quantitative fluorescence data of the cap layer, so that the dispersion mode of oil and gas through the cap layer can be accurately identified, and the problems of randomness and multiple solutions in the prior art can be effectively avoided.

Description

Technical Field

[0001] This invention relates to the field of oil and gas reservoir technology, and more specifically to a method for identifying the ways in which oil and gas are lost through caprock. Background Technology

[0002] As one of the core elements in the formation and preservation of oil and gas reservoirs, the sealing performance of the caprock directly determines whether oil and gas will be lost and the intensity of the loss. The loss mode of oil and gas through the caprock (mainly including slow seepage and curtain-like fracturing) is a key basic parameter for assessing the preservation conditions of oil and gas reservoirs and guiding the deployment of oil and gas exploration.

[0003] From the perspective of caprock sealing mechanisms, physical property sealing and overpressure sealing are two core sealing types. In the physical property sealing system, the lithological composition (such as clay content and particle sorting), thickness, and displacement pressure of the caprock jointly determine its sealing capacity. When the capillary pressure of the caprock is insufficient to block the buoyancy of oil and gas, the physical property sealing system fails, and oil and gas will be continuously lost through slow seepage along the pores and microfractures of the caprock. Although this loss mode is relatively weak, its long-term effect will lead to the decline or even complete destruction of oil and gas reservoir reserves. Especially in the caprock corresponding to deep, low-porosity, and low-permeability reservoirs, such problems have a more significant impact on the efficiency of oil and gas accumulation (Sun Mingliang, Liu Guangdi, Li Jian, 2008. Characteristics and classification criteria of caprocks in gas reservoirs [J] Natural Gas Industry, 28, 8, 36-38.). In overpressured closed systems, when the accumulated formation pressure exceeds the caprock rupture pressure threshold, the caprock will rupture periodically, forming high-conductivity channels. Oil and gas are rapidly dissipated through these channels in a curtain-like rupture manner. This mode is characterized by strong suddenness and large loss, which will directly change the distribution pattern of regional oil and gas resources. In basins with significant overpressure development, such as the Yinggehai-Qiongdongnan Basin, the effect of this oil and gas accumulation and dispersion process on the formation and transformation of oil and gas reservoirs is particularly prominent (Hao Fang, Liu Jianzhang, Zou Huayao et al., 2015. A brief analysis of the oil and gas accumulation and dispersion mechanism of overpressured strata in the Yinggehai-Qiongdongnan Basin [J] Earth Science Frontiers, 22, 1, 169-180.).

[0004] As oil and gas exploration expands into deeper and ultra-deep reservoirs, the burial depth of oil and gas reservoirs continues to increase. These reservoirs generally undergo multiple complex tectonic movements, resulting in varying degrees of damage to the integrity of the caprock. The process of oil and gas loss becomes more complex, and preservation conditions have become a core bottleneck restricting the success rate of deep oil and gas reservoir exploration. However, existing identification technologies for oil and gas loss through caprocks still primarily rely on qualitative analysis of the geological background: determining the presence of slow seepage based on macroscopic characteristics such as the development thickness and lateral continuity of the mudstone caprock; and inferring the possibility of caprock rupture and episodic loss based on parameters such as formation pressure coefficient and overpressure development intensity.

[0005] This qualitative identification method has significant limitations: firstly, the judgment criteria rely on the researcher's accumulated experience, and different researchers interpret geological features differently, leading to a strong degree of subjectivity in the identification results; secondly, a single geological parameter cannot comprehensively reflect the dynamic evolution of caprock sealing performance and the complex process of hydrocarbon loss, easily resulting in "multiple interpretations." For example, in some areas, the caprock exhibits both weak physical sealing characteristics and overpressure anomalies, making it difficult to accurately distinguish the dominant loss mode through macroscopic geological analysis alone. These problems prevent existing technologies from accurately identifying hydrocarbon loss modes through caprocks, thus affecting the reliability of hydrocarbon reservoir preservation condition assessments and hindering the progress of fine-grained deep hydrocarbon exploration. Therefore, there is an urgent need to establish an objective and accurate identification method based on quantitative test data. Summary of the Invention

[0006] The technical problem to be solved by the present invention is to overcome the shortcomings of the prior art and provide a method for identifying the loss of oil and gas through the caprock. The method uses analytical test data obtained by quantitative fluorescence testing of the caprock to distinguish the loss of oil and gas through the caprock, thereby achieving accurate identification and effectively avoiding the problems of arbitrariness and multiple interpretations in the prior art.

[0007] The technical solution of this invention is as follows: A method for identifying the loss of oil and gas through caprock includes the following steps: S1 Select rock cuttings samples and conduct particle fluorescence testing to obtain parameters: Select vertically continuous reservoir and caprock rock cuttings samples and conduct particle fluorescence testing to obtain the parameter QGF-E, which characterizes the content of hydrocarbons adsorbed on the outside of mineral particles, and the parameter QGF-index, which characterizes the content of hydrocarbons inside mineral particles.

[0008] S2 establishes a method for identifying the loss of oil and gas through caprock: The relationship between the hydrocarbon content adsorbed on the outside of reservoir mineral particles and the hydrocarbon content inside the mineral particles is as follows: Figure 1 As shown, it can be found that the parameter QGF-index of hydrocarbon content inside mineral particles and the parameter QGF-E of hydrocarbon content adsorbed on the outside of mineral particles show a positive correlation. This is attributed to the long occurrence time of oil and gas in the reservoir, and the fact that samples with larger adsorbed hydrocarbons have a higher internal hydrocarbon content.

[0009] The relationship between the hydrocarbon content adsorbed on the outside of caprock mineral particles and the hydrocarbon content inside the mineral particles is as follows: Figure 2 As shown, it can be observed that the parameter QGF-index, which represents the hydrocarbon content inside the mineral particles in the caprock, and the parameter QGF-E, which represents the hydrocarbon content adsorbed on the outside of the mineral particles, have a relatively close relationship. Figure 1The relationship between QGF-index and QGF-E is complex. QGF-index initially increases and then remains constant, primarily due to the different ways oil and gas are lost through the caprock. When the caprock's sealing properties are weak, oil and gas slowly permeate through it. In this case, the contact time between caprock particles and oil and gas is relatively long, and the hydrocarbon content adsorbed on the outside of the particles is positively correlated with the hydrocarbon content inside the particles. Simultaneously, if the formation pressure exceeds the caprock's fracturing pressure, the caprock ruptures, increasing the amount of oil and gas lost and significantly increasing QGF-E. Because the contact time between the gas and caprock particles caused by the fracturing is shorter, QGF-index remains unchanged. Therefore, the relationship between QGF-E and QGF-index can be used to identify the mode of oil and gas loss through the caprock: a positive correlation between QGF-E and QGF-index indicates slow permeation; a relatively constant QGF-index as QGF-E increases indicates fracturing.

[0010] Compared with the prior art, the present invention has the following advantages: 1. This invention abandons the existing model that relies on subjective judgment of geological background. Based on the quantitative parameters QGF-E (hydrocarbon content adsorbed on the outside of mineral particles) and QGF-index (hydrocarbon content inside mineral particles) obtained by particle fluorescence testing, it establishes an objective correlation judgment standard, realizing the accurate differentiation of oil and gas loss through caprock dissipation methods (slow seepage / episodic fracturing). This method eliminates the subjective arbitrariness caused by differences in researchers' experience by quantifying data, effectively solving the core problem of "multiple interpretations" in traditional qualitative analysis. The reliability and repeatability of the identification results are greatly improved, providing standardized technical support for the evaluation of oil and gas reservoir preservation conditions.

[0011] 2. The identification principle of this invention is highly consistent with the geological processes of hydrocarbon loss. In the slow infiltration mode, hydrocarbons are in long-term contact with caprock particles, leading to the simultaneous accumulation of externally adsorbed hydrocarbons and internal hydrocarbon content (positive correlation). In the episodic fracturing mode, hydrocarbons migrate rapidly and have short contact times, resulting in a significant increase in only the externally adsorbed hydrocarbon content while the internal hydrocarbon content remains stable. This identification logic based on the differences in hydrocarbon occurrence states directly reflects the essential characteristics of different loss modes, making the identification results not only supported by quantitative data but also consistent with the laws of geological evolution. Its scientific validity and persuasiveness far exceed traditional macro-geological analysis methods.

[0012] 3. In response to the current trend of oil and gas exploration extending to deeper and ultra-deeper reservoirs, and the complex preservation conditions resulting from multiple tectonic movements, the method of this invention is simple to operate and highly adaptable. Identification can be rapidly completed through vertically continuous rock cuttings sampling. Its accurate identification results can precisely reflect the dynamic evolution of caprock sealing performance and the intensity of oil and gas loss, providing key parameters for the classification and evaluation of preservation conditions in deep oil and gas reservoirs and the selection of favorable exploration zones. This effectively reduces the risks of deep oil and gas exploration, improves the targeting and efficiency of exploration deployment, and has significant practical value for promoting refined oil and gas exploration.

[0013] 4. The particle fluorescence test used in this invention is a mature analytical method in oil and gas geological exploration. The test process is standardized, and the data acquisition efficiency is high, without the need for the development of additional complex equipment or technical processes. Identification of loss patterns can be achieved based on existing test data, lowering the technical application threshold and facilitating its application in different exploration areas and different types of oil and gas reservoirs. This provides the oil and gas exploration industry with a low-cost, high-efficiency solution for identifying caprock oil and gas loss patterns. Attached Figure Description

[0014] Figure 1 This is a graph showing the relationship between the hydrocarbon content adsorbed on the outside of reservoir mineral particles and the hydrocarbon content inside the mineral particles in this invention.

[0015] Figure 2 This is a graph showing the relationship between the hydrocarbon content adsorbed on the outside of the caprock mineral particles and the hydrocarbon content inside the mineral particles in this invention.

[0016] Figure 3 This is a graph showing the relationship between the hydrocarbon content adsorbed on the outside of the mineral particles in well A in Embodiment 1 of the present invention and the hydrocarbon content inside the mineral particles.

[0017] Figure 4 This is a graph showing the relationship between the hydrocarbon content adsorbed on the outside of the mineral particles in the B well cover layer and the hydrocarbon content inside the mineral particles in Embodiment 1 of the present invention. Detailed Implementation

[0018] To enable those skilled in the art to better understand the technical solutions of this invention, the technical solutions of this invention will be clearly and completely described below in conjunction with the embodiments of this invention.

[0019] Example 1: Identification of oil and gas loss from well A through caprock (slow seepage type) 1. Sampling Background and Scheme: Well A is located in a hydrocarbon-rich depression slope zone of a basin in western China. The target layer for exploration is the Permian system at a depth of more than 5000m. For the rock cuttings samples of the target layer, one rock cuttings sample is selected every 20m, with a weight of about 50g.

[0020] 2. Testing Procedure and Data Acquisition: The specific procedure and testing conditions for particle fluorescence testing are described in existing techniques (Qu, J.; Liu, K.; Liu, H.; Zhou, M.; Ding, X.; Zha, M. Applying Quantitative Fluorescence Techniques to Investigate the Effectiveness of Deep-Seated Mudstone Caprocks in the Junggar Basin, NW China. Geosciences 2025, 15, 215.). Finally, the QGF-E (hydrocarbon content adsorbed on the exterior of mineral particles) and QGF-index (hydrocarbon content inside mineral particles) parameters of the samples were obtained.

[0021] 3. Data Analysis and Result Determination: Correlation analysis was performed on the QGF-E and QGF-index data of the caprock samples, and scatter plots were drawn (e.g., Figure 3 As shown in the figure, the two are positively correlated. Well A is located in a hydrocarbon-rich depression slope zone with a relatively gentle structure. The pressure system of the target layer is at normal pressure, and the tectonic stress is weak. It does not have the geological conditions to cause the caprock to fracture and form a curtain-like migration channel. Therefore, based on the comprehensive quantitative data and geological conditions, it is determined that the oil and gas in Well A are lost through the caprock by slow seepage.

[0022] Example 2: Identification of oil and gas loss from well B via caprock (episode-type fracture) 1. Sampling Background and Scheme: Well B is located in the uplift zone on the periphery of a hydrocarbon-rich depression in a basin in western my country. The target layer for exploration is the Permian system at a depth of more than 5000m. For the rock cuttings samples of the target layer, one rock cuttings sample is selected every 20m, with a weight of about 50g.

[0023] 2. Testing Procedure and Data Acquisition: The specific operation procedure and testing conditions for particle fluorescence testing are the same as in Example 1. Finally, the QGF-E (hydrocarbon content adsorbed on the outside of mineral particles) and QGF-index (hydrocarbon content inside mineral particles) parameters of the samples were obtained.

[0024] 3. Data Analysis and Result Determination: Analyze the QGF-E and QGF-index data of the caprock samples and plot scatter plots (e.g., ...). Figure 4As shown in the figure, as QGF-E increases from 2 to 400, QGF-index remains between 1 and 10, showing no significant correlation. Well B is located on the periphery of a hydrocarbon-rich depression, where tectonic stress is concentrated and the target layer pressure system exhibits abnormal overpressure. The caprock is prone to episodic fracturing, forming multiple microfracture channels. Oil and gas migrate rapidly through these fracture channels, with extremely short contact time with caprock particles, resulting in adsorbed hydrocarbons only on the particle surface (QGF-E increases significantly), making it difficult to penetrate into the particle interior (QGF-index remains stable). Therefore, it is determined that the oil and gas loss from Well B through the caprock is episodic fracturing.

[0025] The above embodiments, through standardized sampling procedures, precise test data, and comprehensive analysis combined with geological background, fully demonstrate that the method of the present invention can accurately identify the loss modes of oil and gas through caprocks, and the identification results are highly consistent with oil testing data and geological conditions. This method provides quantitative support for the evaluation of oil and gas reservoir preservation conditions and can be widely applied to the identification of oil and gas loss modes in different types of basins and caprocks at different depths. It has significant practical implications for improving the efficiency of deep oil and gas exploration and reducing exploration costs.

Claims

1. A method for identifying the mode of oil and gas loss through caprock, characterized in that, Includes the following steps: S1 Selects vertically continuous reservoir and caprock cuttings samples, conducts particle fluorescence testing, and obtains the parameter QGF-E characterizing the hydrocarbon content on the outside of mineral particles and the parameter QGF-index characterizing the hydrocarbon content inside mineral particles. S2 identifies the mode of oil and gas loss through the caprock based on the relationship between QGF-E and QGF-index. If QGF-E and QGF-index show a positive correlation and both increase with depth in the caprock, it indicates that the oil and gas loss through the caprock is slow infiltration. If QGF-E increases with depth in the caprock while QGF-index remains basically unchanged, it indicates that the oil and gas loss through the caprock is episodic rupture.

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