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The reliance on fossil fuels is a major contributor to increased anthropogenic CO 2 emissions, driving global challenges such as climate change through the greenhouse effect. Carbon capture and storage (CCS) is a promising interdisciplinary technology aimed at mitigating these emissions by securely sequestering gigatons of CO 2 . This study focuses on the feasibility of storing point-source CO 2 emissions in saline formations, with a particular emphasis on the Mae Moh coal-fired power plant in Lampang, Thailand, which is located near its associated coal mine. The region presents challenges due to tight sandstone reservoirs buried over 2000 m deep. With reservoir simulation, this study evaluates the impact of various factors on CO 2 containment and trapping in these geological settings. Results show that elevated temperatures decrease structural trapping of 43.0%-28.9% and increase solubility trapping of 28.55%-46.5%, at 40 °C and 80 °C respectively. Hysteresis is found to enhance residual trapping by immobilizing up to 31.1% of CO 2 within pore spaces at 0.5. Permeability heterogeneity has a minimal impact on overall trapping efficiency due to the less heterogeneity of the tight sandstone. However, the kV/kH ratio significantly influences vertical CO 2 migration which resulted in residual trapping at its highest at the ratio of 0.1, while lower ratios support lateral dispersion. Moderate rock compressibility values are identified as optimal for structural and residual trapping, while extreme compressibility enhances solubility trapping by up to 30%. These findings emphasize the complexity of CO 2 trapping mechanisms in tight sandstone formations, emphasizing the need for careful consideration of key factors in CCS projects., Competing Interests: Declaration of competing interest The author declares that he has no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper., (Copyright © 2024 Elsevier Ltd. All rights reserved.)

The objective of this research is to compare water and polymer flooding case studies by using a reservoir simulation to simulate the improvement of oil recovery in the reservoir of the U-Thong oil field and to study the economics of both methods to find the best case scenario. The physical properties of the reservoir rock and fluids, porosity, permeability, and reservoir pressure were collected from a literature review and theoretical assumptions. The reserve size of the reservoir is around 6.48 million barrels injected with a direct drive pattern (2 production wells and 2 injection wells) in the 1st year. Results of this research revealed that polymer flooding is the best method./, as the summary of the oil recovery factor and net present value result is 55.03% and 35.53 MMUS$, respectively (more than water flooding at 5.57% and 2.52 MMUS$, respectively). [ABSTRACT FROM AUTHOR]

This paper examines 2 questions: (1) the study and comparison of oil recovery efficiency between the best case of waterflooding and polymer flooding by using the reservoir simulation technique and (2) the application of the discount cash flow to optimize the polymer flooding selection from each scenario under current Dubai oil prices. Three sizes of oil fields are modeled in an anticline reservoir structure with the original oil in place (OOIP) of 100, 30, and 5 million barrels respectively. Each oil field has many production methods using different polymer concentrations and injection periods. In the large size reservoir model A100, oil recovery has an increase from waterflooding of 3.86-7.24% OOIP. The polymer flooding has an internal rate of return (LRR) range from 28.40-43.76% and a profit to investment ratio (PIR) of 0.37-0.51; the best case scenario is the one that used a polymer concentration of 1000 ppm and an injection period of the 3rd-11th years and which has a net present value (NPV) of $170M. In the medium size reservoir model A30, oil recovery has an increase from waterflooding of 2.42-5.48% OOIP. The polymer flooding has an IRR range from 53.91-56.76% and a PIR of 0.36-0.40; the best case scenario is the one that used a polymer concentration of 1000 ppm and an injection period of the 3rd-10th years and which has an NPV of $53M. In the small size reservoir model A05, oil recovery has an increase from waterflooding of 4.39-4.62% OOIP. The polymer flooding has an IRR range from 20.95-21.73% and a PIR of 0.66-0.76, and the best case scenario is the one that used a polymer concentration of 600 ppm and an injection period of the 4th-20th years and which has an NPV of $15M. [ABSTRACT FROM AUTHOR]