GSA Annual Meeting in Phoenix, Arizona, USA - 2019

Paper No. 80-3
Presentation Time: 8:40 AM


DUNSEITH, Regina F., Boone Pickens School of Geology, Oklahoma State University, 105 NRC, Stillwater, OK 74078, GREGG, Jay M., Boone Pickens School of Geology, Oklahoma State University, 105 Noble Research Center, Stillwater, OK 74078-3031 and GRAMMER, G. Michael, Boone Pickens School of Geology, Oklahoma State University, Noble Research Center, Stillwater, OK 74078

Fault-fracture oil fields in the Trenton and Black River formations (TBR) constitute important petroleum reservoirs in the southern Michigan Basin and are the type example for “hydrothermal” petroleum reservoirs world-wide. The fields are structurally related and controlled by SE to NW trending fault systems. They include the Albion, Napoleon, Northville, Scipio, Stony Point, and several smaller fields. These oil fields share many characteristics in common with Mississippi Valley-type mineral deposits including dolomitized breccias, coarse crystalline carbonate cements, and sulfide mineralization.

Fluid inclusion homogenization temperatures (Th) (79ºC to 258ºC) for carbonate cements from six oil fields and one unproductive well indicate two fluid end members: a warm fluid (<180ºC) and a hot fluid (>180ºC). Decreasing average Th values distal from the Proterozoic Mid-Michigan Rift in southeastern Michigan suggest that the hot fluids emanated from the rift area in the underlying basement. Fluids are saline (16.1 to 49.4 wt. % NaCl equivalent) and likely ultimately sourced from Salina Group (Silurian) evaporites. Eutectic temperatures (Te) (-50ºC to -112ºC) suggest a complex Na-Ca-KCl brine.

Strontium isotope values of carbonate cements (0.7086 to 0.7110) are consistent with two fluid sources: Proterozoic basement and late Silurian evaporites. Carbonate cements are depleted with respect to δ18O (-6.59 to -12.46‰VPDB) and somewhat depleted with respect to δ13C (-1.22 to +1.18‰VPDB). Equilibrium calculations from δ18O and Th values indicate cement-precipitating waters were highly evolved (+1.3 to +14.4‰ δ18OVSMOW) compared to Middle Ordovician and Late Silurian seawaters (-7.5‰ to -5.5‰ and -6.5‰ to ‑3.5‰ δ18OVSMOW respectively).

Hydrothermal fluids in TBR oil fields likely have similar sources and timing. However, cathodoluminescence cement stratigraphies indicate that water-rock interactions along fault pathways modified source waters, giving each oil field a unique petrographic and geochemical signature. Reactivation of basement faulting and fluid movement in TBR oil fields likely occurred during Silurian-Devonian tectonism.

  • T46 80-3 Dundeith-Gregg-Grammer GSA 2019.pptx (15.9 MB)