Wettability of Tight Sandstone Reservoir and Its Impacts on the Oil Migration and Accumulation: A Case Study of Shahejie Formation in Dongying Depression, Bohai Bay Basin

Jia, Kunkun; Zeng, Jianhui; Wang, Xin; Li, Bo; Gao, Xiangcheng; Wang, Kangting

doi:10.3390/en15124267

Cited by 7 publications

(5 citation statements)

References 59 publications

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“…During the simulation, the thermodynamic temperature T = 298.15 K, the temperature difference Δ T = 20, the ratio of r max0 to r min0 is 100, the friction coefficient of contact line ζ = 0.02 Pa·s, the capillary number Ca = 0.002, the pinning coefficient C pin = 5.6 mN/m, the smoothing parameter C = 2.5 × 10 4 , the elastic modulus E = 25 GPa, Poisson’s ratio υ = 0.25, the power law index β = 2/3, the shape factor F = 4, the linear expansion coefficient α = 1.4 × 10 –5 K –1 , constant B 1 = 8.038, constant B 2 = −1 × 10 3 , and the ultimate shear stress τ 0 = 50 Pa by laboratory tests . In general, there are various minerals in shale oil reservoirs, which result in the complicated wettability of shale oil porous materials . Based on experimental tests, many researchers have found that shale oil reservoirs were weak oil-wet. , Thus, for the sake of simplicity, in this work, the equilibrium contact angle θ e is assigned as 115°.…”

Section: Resultsmentioning

confidence: 99%

“…32 In general, there are various minerals in shale oil reservoirs, which result in the complicated wettability of shale oil porous materials. 79 Based on experimental tests, many researchers have found that shale oil reservoirs were weak oil-wet. 80,81 Thus, for the sake of simplicity, in this work, the equilibrium contact angle θ e is assigned as 115°.…”

Section: Tpg Model Validationmentioning

confidence: 99%

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A Novel Threshold Pressure Gradient Model and Its Influence on Production Simulation for Shale Oil Reservoirs

Qu,

Tang,

Lei

et al. 2024

Energy Fuels

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Accurate characterization of the threshold pressure gradient (TPG) in shale oil reservoirs is essential for oil production. However, oil−water two-phase flow through shale oil reservoirs with narrow pores involves thermal−hydrological−mechanical coupling, and the relationship between TPG and pore structures under multiple mechanisms has not been adequately modeled mathematically. In this paper, an analytical TPG model of shale oil reservoirs is derived first by considering the combined effects of effective stress, temperature, capillary pressure, pore structures, and boundary layer. After the established model is adequately verified by the obtainable experimental data, it is embedded into a multistage fractured horizontal well productivity model to investigate the influence of relevant parameters on shale oil production. The simulation results suggest that the TPG for the oil phase increases with the increase in effective stress, leading to the decrease in shale oil production. The cumulative oil production with dynamic TPG is much greater than that considering fixed TPG. Moreover, the wettability of the oil−water two phase (e.g., oil−water interfacial tension and equilibrium contact angle) has crucial influences on well performance; thus, changing the wettability of the oil−water two phase by chemical injection is an effective method to enhance oil recovery. The research results can provide technical support for the efficient development of shale oil reservoirs from the perspective of pore-scale two-phase nonlinear flow characteristics and macroscopic productivity evaluation.

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Section: Resultsmentioning

confidence: 99%

Section: Tpg Model Validationmentioning

confidence: 99%

A Novel Threshold Pressure Gradient Model and Its Influence on Production Simulation for Shale Oil Reservoirs

Qu,

Tang,

Lei

et al. 2024

Energy Fuels

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“…The permeability attributes and efficiency of oil displacement via water injection in a reservoir are significantly influenced by its wettability [62,63]. It is clear that the relative wettability index of all samples, barring X4, shares a robust positive correlation with both the oil displacement efficiency in the non-aqueous phase and the ultimate oil displacement efficiency (Table 5 and Figure 17).…”

Section: The Relationship Between Micro-heterogeneity and Wettabilitymentioning

confidence: 98%

The Influence of Micro-Heterogeneity on Water Injection Development in Low-Permeability Sandstone Oil Reservoirs

Li,

Qu,

Wang

et al. 2023

Minerals

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Micro-heterogeneity in low-permeability sandstone oil reservoirs significantly influences the uniformity of water injection during development. This leads to the formation of preferred channels for water injection, causing premature water breakthroughs in oil wells. Not only does this reduce oil displacement efficiency, but it also enriches residual oil in the formation, which ultimately impacts the overall recovery rate. This study employed various methods, including thin-section casting, qualitative analysis through scanning electron microscopy, quantitative analysis of X-ray diffraction, high-pressure mercury intrusion and particle size, and experimental techniques, such as wettability and micro-displacement, to investigate the impact mechanism of micro-heterogeneity on water injection development in low-permeability oil reservoirs. A typical low-permeability sandstone oil reservoir in the Ordos Basin was used as a case study. The results reveal that the reservoir’s micro-heterogeneity is determined by the heterogeneity of the interstitial material, porosity, and particle size. Micro-heterogeneity plays a critical role in the flow characteristics and oil displacement efficiency of low-permeability oil reservoirs. The less the micro-heterogeneity, the better the water injection development outcome. This study suggests a technical policy adjustment method that is critical for guiding the development of low-permeability water injection oil reservoirs, thereby improving the effectiveness of water injection development.

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“…Regarding life cycle assessment, more energy is consumed to store up to 56% of CO 2 than is generated from the extra oil produced. Water-alternating gas (WAG) has also been exploited for the same purpose in EOR [57][58][59][60][61]; however, this injection strategy has not yet been applied or studied extensively in geological CO 2 storage in DSFs.…”

Section: Injection Strategy As a Means Of Reducing Wamentioning

confidence: 99%

Experimental Investigation of the Impact of CO2 Injection Strategies on Rock Wettability Alteration for CCS Applications

Eyitayo,

Talal,

Kolawole

et al. 2024

Energies

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Carbon capture and storage (CCS) has been recognized as a pivotal technology for mitigating climate change by reducing CO2 emissions. Storing CO2 in deep saline aquifers requires preserving the water-wet nature of the formation throughout the storage period, which is crucial for maintaining rock integrity and storage efficiency. However, the wettability of formations can change upon exposure to supercritical CO2 (scCO2), potentially compromising storage efficiency. Despite extensive studies on various factors influencing wettability alteration, a significant research gap remains in understanding the effects of different CO2 injection strategies on wettability in deep saline formations (DSFs). This study addresses this gap by investigating how three distinct CO2 injection strategies—continuous scCO2 injection (CCI), water alternating with scCO2 injection (WAG), and simultaneous water and scCO2 injection (SAI)—affect the wettability of gray Berea sandstone and Indiana limestone, both selected for their homogeneous properties relevant to CCS. Using a standardized sessile drop contact angle method before and after CO2 injection, along with core flooding to model the injection process at an injection pressure of 1500 psi and temperature of 100 °F with a confining pressure of 2500 psi, the results indicate a shift in wettability towards more CO2-wet conditions for both rock types under all strategies with changes in CA of 61.6–83.4° and 77.6–87.9° and 81.5–124.2° and 94.6–128.0° for sandstone and limestone, respectively. However, the degree of change varies depending on the injection strategy: sandstone exhibits a pronounced response to the CCI strategy, with up to a 77% increase in contact angle (CA), particularly after extended exposure. At the same time, WAG shows the least change, suggesting that water introduction slows surface modification. For limestone, the changes in CA ranged from 9% to 49% across strategies, with WAG and SAI being more effective in altering its wettability. This study underscores the importance of selecting suitable CO2 injection strategies based on rock type and wettability characteristics to maximize carbon storage efficiency. The findings offer valuable insights into the complex interactions of fluid–rock systems and a guide for enhancing the design and implementation of CCS technologies in various geological settings.

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Wettability of Tight Sandstone Reservoir and Its Impacts on the Oil Migration and Accumulation: A Case Study of Shahejie Formation in Dongying Depression, Bohai Bay Basin

Cited by 7 publications

References 59 publications

A Novel Threshold Pressure Gradient Model and Its Influence on Production Simulation for Shale Oil Reservoirs

A Novel Threshold Pressure Gradient Model and Its Influence on Production Simulation for Shale Oil Reservoirs

The Influence of Micro-Heterogeneity on Water Injection Development in Low-Permeability Sandstone Oil Reservoirs

Experimental Investigation of the Impact of CO2 Injection Strategies on Rock Wettability Alteration for CCS Applications

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