Pore Structure Characteristics and Controlling Factors of a Tight Sandstone Reservoir in the Paleogene Shahejie Formation, Nanpu Sag, Bohai Bay Basin, China

Shahejie marl in the Shulu Sag is a crucial resource for unconventional hydrocarbon exploration in China. Although breakthroughs have been made in tight oil exploration in this area, the mechanisms underlying the formation of this marl reservoir and factors controlling its ‘sweet spots’ have not been thoroughly studied. To understand the pore structure characteristics and factors influencing the marl reservoir, we analyzed core samples from Wells ST1 and ST3. A series of experiments was conducted on the samples, such as X-ray diffraction, focused ion beam scanning electron microscopy, micro-CT, and total organic carbon test. Additionally, the physical properties of different marl rock fabrics were studied with auxiliary tests, such as mercury intrusion capillary pressure analyses, nuclear magnetic resonance, porosity and permeability tests, and thin-section observation. The results revealed that the marl reservoir is characterized by low porosity (1.61%) and low permeability (2.56mD). The porosity and permeability (1.61% and 3.26mD) of laminated marl were better than those (0.92% and 1.68mD) of massive marl. Clay minerals and quartz content in laminated (11.8 and 8.2%) was less than in massive marl (16.2 and 13.3%). The marl pores include intercrystalline pores, dissolution pores, and microfractures. Additionally, the laminated marl pores were primarily distributed along the dark lamina, with good connectivity. A few isolated and uniform holes were observed in the massive marl. Influenced by rock fabric and mineral composition, layered fractures were mainly developed in the laminated marl, while structural fractures were the main type of microfractures in the massive marl. The primary sedimentary mechanism was the main geological action underlying the differences in marl rock fabric; this mechanism affects the physical properties of the marl reservoir, which are key factors to be considered when searching for the marl reservoir ‘sweet spots’. Particular attention should be paid to these factors during tight oil exploration and development in similar sedimentary basins.

“…Dissolution significantly improves the quality of the marl reservoir (Yang et al, 2022). SEM revealed the widespread dissolution pores with large diameters (Figures 6B,E,G,I).…”

Section: Dissolutionmentioning

confidence: 93%

Reservoir characteristics and factors influencing shahejie marl in the shulu sag, bohai bay basin, eastern China

Fu²,

Zhu³

et al. 2022

“…The MICP method can measure the radius distribution of pores and throats (Okolo et al, 2015;Zhang et al, 2020;Yang et al, 2022), which was conducted at Shengli Oilfield using the Auto Pore 9500 automatic mercury injection instrument. First, the samples were washed to remove salt and oil, then dried for 48 h at 96°C, and stored in a vacuum.…”

Section: Micp Testsmentioning

confidence: 99%

Quantitative characterization of the carbonate rock microstructure considering topological features: a case study from the Gaoshiti–Moxi block of the Sichuan Basin

Dong,

Luo,

Dang

et al. 2024

The precise characterization of the rock microstructure is crucial for predicting the physical characteristics, flow behavior, and mechanical properties of rocks. This is particularly important for carbonate rocks, which depict a complex microstructure with multimodal pore radius distribution and natural fractures. Here, topological features that are typically ignored are taken into account to quantify the carbonate microstructure. Carbonate samples used are obtained from the Gaoshiti–Moxi block of the Sichuan Basin, which showed remarkable potential for oil and gas. Specifically, nuclear magnetic resonance (NMR), X-ray micro-computed tomography (micro-CT), and mercury injection capillary pressure (MICP) techniques are performed to describe the topological and geometric characteristics. The results indicate that NMR and MICP techniques can describe more rock pores than micro-CT. However, due to the presence of pore shielding in MICP tests, the pore radius obtained by MICP is smaller than that obtained by micro-CT and NMR. Furthermore, the effective method used for characterizing the pore structure is NMR technology. The hardest part is that the coefficient between the pore radius and T2 relaxation time is difficult to calculate. Therefore, a better calculation method must be found. In addition, micro-CT is an irreplaceable technique for obtaining a large number of topological and geometric features, and multi-phase or single-phase flow simulations can be conducted via digital rock models. However, for carbonates, micro-CT is not sufficient to describe the complete pore systems because macropores cannot be fully represented and sub-resolution micropores cannot be described. Those macropores and micropores have a very important effect on their seepage properties. Therefore, multi-scale digital rock modeling involving small and large pores is essential for complex rocks, which is of great significance for the analysis of pore systems and the simulation of rock physical properties.

“…The complex pore structure of carbonate rocks leads to low permeability of pore space, which has a great influence on natural gas production rate. In recent years, researchers have studied the microscopic pore structure of rocks by using constant rate mercury injection (Pan et al, 2022;Yang et al, 2022), micro-CT scanning (Zhang et al, 2010; and Scanning Electron Microscopy (SEM) (Pan et al, 2022). However, it is necessary to comprehensively consider the influence of fluid flow process in the structural analysis of carbonate rock, and establish fluid flow model in the complex pore structure of carbonate rock, so as to achieve effective prediction of permeability.…”

Section: Introductionmentioning

confidence: 99%

Research of influencing factors on permeability for carbonate rocks based on LBM simulation: A case study of low-permeability gas reservoir of Sinian Dengying Formation in Sichuan Basin

Yang

Xian³

et al. 2023

Instruction: Due to the declining production rate of conventional natural gas reservoir and the rising demand for natural gas resources, conventional natural gas resources cannot satisfy the needs of economic development. Unconventional gas resource is considered to be the most promising energy supplement, therefore it is an inevitable trend to explore and develop unconventional oil and gas resources such as low permeability reservoirs. At present, the carbonate gas reservoirs in the high permeability area of Sichuan Basin have been almost fully developed, while the remaining gas reservoirs in the low permeability area are not well developed. However, the key factors for effectively enhancing gas recovery rate in different types of low permeability reservoirs are not the same. Even gas reservoirs with the same macroscopic geological characteristics will show different development characteristics through the production processes.Method: In order to analyze the factors affecting the effective production rate of low-permeability gas reservoirs, it is necessary to conduct research from the microscopic perspective, to reveal the effective production conditions of natural gas in low-permeability reservoirs. In this study, low-permeability carbonate samples of Sinian Dengying Formation from Sichuan Basin were taken. Micro-CT scanning technology was used to obtain core images for the carbonate rocks, and the digital carbonate core models at microscopic scale were reconstructed. Based on the reconstructed carbonate digital core models, LBM method was applied to obtain the absolute permeability of the core models.Results: The results imply that the porosity, pore area fraction, throat area fraction, mean throat length, shape factor, coordination number and tortuosity are the factors affecting the absolute permeability of carbonate rocks.Discussion: Subsequently, the relationship between different pore structure parameters and absolute permeability was obtained by multi-parameter fitting method, which provided a new research method for directly predicting the absolute permeability of carbonate rocks by using pore structure parameters.