Paleohydrology and Machine-Assisted Estimation of Paleogeomorphology of Fluvial Channels of the Lower Middle Pennsylvanian Allegheny Formation, Birch River, WV

Rivers transport sediments in a source to sink system while responding to allogenic controls of the depositional system. Stacked fluvial sandstones of the Middle Pennsylvanian (Desmoinesian Stage, ∼310–306 Ma) Allegheny Formation (MPAF) exposed at Birch River, West Virginia exhibit change in sedimentary structure and depositional style, reflecting changes in allogenic behavior. Paleohydrologic and numerical analysis were used to quantify geomorphological and paleohydrologic variations reflected by MPAF fluvial deposits with the goal of understanding the controls on resulting fluvial sandstone architecture in these different systems. Channel body geometry, sedimentary structures, and sandstone grain size distribution were used to reconstruct the paleoslope and flow velocity of the MPAF fluvial systems. In order to enhance paleohydrological estimates, machine learning methods including multiple regression and support vector regression (SVR) algorithms were used to improve the dune height, and channel depth estimated from cross-set thickness. Results show that the channel depths of the lower MPAF beneath the Lower Kittanning coal beds tend to decrease upsection; this decrease is interpreted to reflect a transition from fluvial systems formed in a humid ever-wet climate to fluvial systems formed in less humid, seasonally wet, semi-arid climate. Paleohydrologic estimations enabled the evaluation of hydraulic changes in the fluvial depositional systems of the Appalachian Basin during the Desmoinesian stage. Paleoslope estimates indicated that the slope was low, which indicated that the fluvial gradient response was not driven by the effect of tectonic subsidence or uplift and sea-level change

Petrologic evidence for the diagenesis of the Donovan Sand, Citronelle Field, Alabama, and implications for CO2 storage and enhanced oil recovery

Geological sequestration of CO2 for enhanced oil recovery (EOR) has been in use for decades, but it now represents a potentially economical method of mitigating anthropogenic CO2 output. However, current understanding of the interaction between injected CO2 and the reservoir rock is limited and prevents accurate estimation of reservoir CO2 capacity. Delineating the diagenesis of the reservoir is useful in predicting post-CO2 injection changes in reservoir porosity and permeability. The Albian Donovan Sand member of the Rodessa Formation, Citronelle Field, Alabama, is the subject of an ongoing Department of Energy CO2-EOR suitability study. The arkosic Donovan Sand is highly heterogeneous, containing conglomeratic intervals, low to extensive poikilotopic calcite cement, loose to tight grain packing, and low <1% to high (5%) porosity (primary and secondary) observed in thin section. It forms the basal members of laterally discontinuous upward-fining parasequences that define a marine to brackish to fluvial delta system. The diagenesis of the Donovan Sand occurred in five stages: 1) pre-burial and compaction–formation of extensive calcite cement; 2) partial dissolution of calcite cement and framework feldspars; 3) secondary calcite cementation, localized dolomitization, and calcite and anhydrite concretion formation; 4) hydrocarbon charge; and 5) pyrobitumen development. Primary porosity is dominant, but substantial secondary porosity was formed during stage 2. Following injection of CO2, water injection and oil and gas production rates dropped below modeled values. We propose that the CO2 injection dissolved calcite cement proximal to the injection well and reprecipitated it nearby with the effect of reducing porosity and/or permeability