ABSTRACT The Middle Devonian Sylvania Sandstone in the Michigan Basin, United States, is noteworthy for its mixed, cherty dolomitic carbonate, limestone, and sandstone composition and excellent reservoir quality and fluid-flow properties in many areas of the basin. Substantial commercial brine production was initiated in the middle twentieth century, and liquid waste disposal continues today in the Sylvania Sandstone, although little or no hydrocarbon production is known from this unit. The Sylvania Sandstone pinches out to the south and west in the basin and overlies either the Bass Islands Group at the regional base Kaskaskia unconformity to the south or the Bois Blanc Formation, with which it is proposed to be in facies relationship to the northeast. The Sylvania Sandstone is overlain by and apparently interfingers with the Meldrum Member of the Amherstburg Formation throughout the basin. The Sylvania unit predominantly consists of siliciclastic rocks in the southeastern Michigan Basin and in outcrop in Ohio, but it is transitional to predominantly cherty carbonate in the northwest along a depositional hinge striking from southeast to northwest through the central basin. This hinge zone is dominated by mixed carbonate and siliciclastic strata deposited in normal-salinity, tidally influenced paralic and shallow-marine environments. Excellent reservoir quality is present in quartz sandstones and, especially, mixed sandy dolomite lithofacies in the central basin. Cherty facies may also possess significant porosity, but typically with low permeability. Limestone lithofacies are commonly non-reservoir-quality facies. Multiple high-frequency, low-magnitude relative sea-level cycles within the Sylvania Sandstone are suggested from regional stratigraphic analysis. The Sylvania Sandstone in the Michigan Basin is interpreted as a mixed carbonate and siliciclastic, basin-margin facies assemblage deposited in an overall transgressive systems tract above the base Kaskaskia unconformity and in conformable relationship with more basinal facies of the Bois Blanc Formation.

Abstract Existing subsurface data and data from core and logs in a new CO 2 pilot injection test well drilled in northern lower Michigan were used to evaluate the geological carbon sequestration (GCS) potential in Upper Silurian to Middle Devonian saline reservoir and cap-rock units in the Michigan Basin. The Core Energy-State Charlton #4-30 well, Otsego County, Michigan, was drilled as part of ongoing Midwest Region Carbon Sequestration Partnership (MRCSP) phase II studies to investigate GCS potential in these units in the Michigan Basin. Significant GCS potential is recognized in porous dolomite of the Upper Silurian, Bass Islands Group in the new well. Cherty strata of the Bois Blanc Formation are also present in the #4-30 well but may lack suitable injectivity for consideration of GCS. Argillaceous limestone in parts of the superjacent Amherstburg Formation in the test well contains minimal porosity and permeability and constitutes an excellent cap-rock unit in the area. Regional consideration of the Bass Islands sequestration target interval indicates substantial GCS potential throughout most of the Michigan Basin. Preliminary estimates of regional GCS storage capacity range from 1.34 billion metric tonnes at 2% displacement storage efficiency to 6.7 billion metric tonnes of CO 2 at 10% storage efficiency in the study area. These displacement storage capacities equate to approximately 288–1440 t of CO 2 per hectare (117–583 t/ac) given the regional estimates of average thickness and porosity in the target interval used here. Significant drilling fluid loss into the target injection interval observed during drilling of the State Charlton #4-30 well of about 3.2 m 3 /hr (20 bbl/hr) demonstrates substantial injectivity in the pilot test well. Considering the fluid loss during drilling and measurements of conventional petrophysical properties in the injection target, the proposed CO 2 injection test volume of 10,000 t could fill the target interval in an area of at most 35 ha (86 ac) in the subsurface, depending on displacement storage volume efficiency assumptions. These preliminary assumptions and simple calculations indicate that the CO 2 injection plume for the injection test would extend no more than 600 m (1970 ft) away from the borehole in all directions. Preliminary reservoir simulations, using other assumptions, suggest a substantially less extensive invasion of the target interval during the injection test.