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Pore Size Distribution on OGIP, a Woodford Shale Case Study


Adsorption in kerogen pores in organic-rich shale and tight rocks is often quantified by methane Langmuir isotherms up to typically 1200 psia. However, experiments have shown that at reservoir condition, which is usually much higher than 1200 psia, mono-layer assumption might be inaccurate. This paper presents a novel optimized Simplified Local Density algorithm with experiment validation using Woodford core samples that captures how methane isotherms may be affected significantly at a higher pressure. The new finding may influence petroleum production and reserve substantially in organic-rich unconventional reservoirs. Adsorption model for unconventional oil and gas is imperative to evaluate reserves and to estimate production performance. By properly modeling adsorption in shale formations under reservoir condition, we may rectify underestimation for reserves and original fluid in place to a significant degree, and impact operational decisions concerning productions in unconventional reservoirs. Results show that adsorption behaves significantly different at reservoir condition than the lab condition, owing primarily the pressure applied. The new method demonstrates a significant difference in volumetric and flow properties as reservoir depletes. 2. A substantial increase in gas resource is observed when multi-layer adsorption is properly modeled, as compared with using conventional Langmuir isotherms.