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Jurassic Norphlet Formation sandstone reservoirs in Mobile Bay (offshore Alabama, USA) produce gas from great depths (>6.4 km) and elevated temperatures (>200 °C). Quartz cement is concentrated at the top of these aeolian reservoirs forming a low porosity ‘tight-zone’ of widely variable thickness (3–58 m) above a more porous reservoir section. The extent of the tight-zone is independent of depositional facies and its thickness strongly influences well performance. Intergranular porosity in the Norphlet has been preserved by inhibition of quartz cementation due to the occurrence of robust grain-coating chlorite. Quantitative petrographic data reveal that chlorite grain-coat coverage is less in the tight-zone sands (mean = 92%) than in the reservoir sands (mean = 99%). Burial history and quartz precipitation kinetics modelling indicate that this seemingly minor difference in the completeness of grain coatings is sufficient to produce the observed differences in cementation and porosity. Quartz cementation to form the tight-zone took place under conditions of deep burial and high temperature. It followed in time the onset of pressure solution, emplacement of liquid hydrocarbons, and the precipitation of a solid hydrocarbon film (pyrobitumen) on the walls of the intergranular pores. Fluid inclusion microthermometry data indicate that volumetrically significant quartz cement precipitated at temperatures of 150 °C or greater from highly saline aqueous fluids. Hydrocarbon-bearing inclusions are notably absent in quartz cement of the tight-zone, implying that the pore fluids were predominantly brine during precipitation. Oil and gas associated with pyrobitumen evidently escaped from Norphlet traps prior to tight-zone cementation. Gas presently found in Norphlet reservoirs of Mobile Bay represents a relatively recent accumulation and is not the product of in situ thermal cracking of oil.

Fast and reliable EOR process selection is a critical step in any EOR project. The digital rock (DR) approach jointly developed by Shell and SLB is aimed to be the smallest scale yet advanced EOR Pilot technology. In this document, we describe the application of DR technology for screening of different EOR mechanisms at pore-scale focused to enhance recovery from a particular reservoir formation. For EOR applications DR brings unique capabilities as it can fully describe different multiphase flow properties at different regimes. The vital part of the proposed approach is the high-efficient pore-scale simulation technology called Direct Hydrodynamics (DHD) Simulator. DHD is based on a density functional approach applied for hydrodynamics of complex systems. Currently, DHD is benchmarked against multiple analytical solutions and experimental tests and optimized for high performance (HPC) computing. It can handle many physical phenomena: multiphase compositional flows with phase transitions, different types of fluid-rock and fluid-fluid interactions with different types of fluid rheology. As an input data DHD uses 3D pore texture and composition of rocks with distributed micro-scale wetting properties and pore fluid model (PVT, rheology, diffusion coefficients, and adsorption model). In a particular case, the pore geometry comes from 3D X-ray microtomographic images of a rock sample. The fluid model is created from lab data on fluid characterization. The output contains the distribution of components, velocity and pressure fields at different stages of displacement process. Several case studies are demonstrated in this work and include comparative analysis of effectiveness of applications of different chemical EOR agents performed on digitized core samples.