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<p>High-temperature drilling environments often intensify rock–fluid interactions, leading to substantial formation damage primarily due to excessive mud filtrate invasion. Conventional additives employed to mitigate this issue frequently exhibit thermal degradation, limiting their effectiveness under elevated temperatures. Notably, the literature reveals a significant gap concerning the invasion behavior of bentonite-free mud filtrate within payzone sections which is considered a critical aspect for optimizing hydrocarbon recovery. This study investigates the influence of drilling mud filtrate–rock interactions on rock strength and porosity at high temperatures through an integrated approach combining laboratory experiments and computational fluid dynamics (CFD) simulations. Rock strength of sandstone and limestone was quantified using unconfined compressive strength (UCS) tests. Experimental findings indicate a significant reduction in strength following filtrate exposure. Bandera Brown exhibited a 33.42% strength reduction after 24&#xa0;h at 300 ℉. Micro-computed tomography (µCT) imaging facilitated pore-scale characterization, revealing significant alterations in porosity and pore network architecture under prolonged exposure. Specifically, Bandera Brown’s porosity increased by 16.5%, whereas Boise Sandstone demonstrated a 37.64% decline over the same period. CFD simulations further interpreted invasion dynamics, showing that high porosity mitigates penetration depth, while increased permeability, extended exposure duration, and higher pressure differentials promote deeper filtrate infiltration. These results highlight the critical role of pressure management in minimizing formation damage. This research provides novel insights into the complex interplay between mud filtrate and reservoir rock properties under high-temperature conditions, offering practical implications for drilling fluid design and wellbore stability in the oil and gas industry.</p>

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Porous media evaluation and formation damage mechanism study: micro CT scanning and CFD analysis perspectives

  • 期刊论文

  • 出版模式：

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  • 发表日期：

    2026年7月8日

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  • Imtiaz Ali,
  • Maqsood Ahmad

摘要

High-temperature drilling environments often intensify rock–fluid interactions, leading to substantial formation damage primarily due to excessive mud filtrate invasion. Conventional additives employed to mitigate this issue frequently exhibit thermal degradation, limiting their effectiveness under elevated temperatures. Notably, the literature reveals a significant gap concerning the invasion behavior of bentonite-free mud filtrate within payzone sections which is considered a critical aspect for optimizing hydrocarbon recovery. This study investigates the influence of drilling mud filtrate–rock interactions on rock strength and porosity at high temperatures through an integrated approach combining laboratory experiments and computational fluid dynamics (CFD) simulations. Rock strength of sandstone and limestone was quantified using unconfined compressive strength (UCS) tests. Experimental findings indicate a significant reduction in strength following filtrate exposure. Bandera Brown exhibited a 33.42% strength reduction after 24 h at 300 ℉. Micro-computed tomography (µCT) imaging facilitated pore-scale characterization, revealing significant alterations in porosity and pore network architecture under prolonged exposure. Specifically, Bandera Brown’s porosity increased by 16.5%, whereas Boise Sandstone demonstrated a 37.64% decline over the same period. CFD simulations further interpreted invasion dynamics, showing that high porosity mitigates penetration depth, while increased permeability, extended exposure duration, and higher pressure differentials promote deeper filtrate infiltration. These results highlight the critical role of pressure management in minimizing formation damage. This research provides novel insights into the complex interplay between mud filtrate and reservoir rock properties under high-temperature conditions, offering practical implications for drilling fluid design and wellbore stability in the oil and gas industry.