USGS Assessment, New Technology Point To Michigan Potential

(Tech Connections Column, December 2005, American Oil and Gas Reporter)

Oil was initially produced in Michigan in the mid-1880s, but commercial production began in 1925. Through the decades there have been several production peaks as different reservoirs were developed, the most prolific being the Silurian Niagara reefs in the 1970s and ’80s.

Current production is only a shadow of its former self, but that doesn’t mean it is over. The U.S. Geological Survey estimates the Michigan Basin has 990 million barrels of oil, 11 trillion cubic feet of gas, and another 220 MMbbl of natural gas liquids (mean values) in undiscovered, technically recoverable resources (http://pubs.usgs.gov/fs/2005/3070/2005-3070.pdf). These conclusions were shared during a PTTC/Michigan Oil & Gas Association workshop. An earlier PTTC workshop, which is summarized online at www.pttc.org/solutions/sol_2004/538.htm, had presented preliminary findings.

The assessment covers Michigan and parts of Illinois, Indiana, Minnesota, Ohio and Wisconsin. USGS defined six total petroleum systems and 13 assessment units (or reservoir intervals). Nine of the 13 assessment units are conventional reservoirs and the remaining four are coals or shales. USGS estimates remaining resources for nine of the assessment units (eight conventional and the unconventional Devonian Antrim).

So, based on this analysis, where is the largest undiscovered potential? For oil, look to the Ordovician Trenton-Black River with an estimated mean of 723 MMbbl. Here reservoir rocks are fractured limestone with hydrothermal dolomite. Traps can be structural and/or stratigraphic.

For gas, look to the Devonian Antrim with an estimated mean of 7 Tcf. Gas is present throughout the Antrim, but production is confined to the northern part of the lower peninsula, where the shales are extensively fractured. Production is further confined to the black shale facies of the lower Antrim (Lachine and Norwood members), where fractures are more pervasive and wider. The Antrim Shale has not entered the gas window, so gas is primarily biogenic.

Christopher Swezey led the USGS team that characterized the hydrocarbons from the five major producing intervals. It found seven chemically distinct natural gases and four chemically distinct oils. Gas data came from more than 2,600 analyses. Some indications of cross-formational leakage were found for both oil and gas.

Additional speakers discussed other tools and how they could be applied for exploration and production. G. Michael Grammer of Western Michigan University reviewed developments in applying carbonate sedimentology and stratigraphy to reservoir characterization, illustrated with examples from research at WMU. William “Bill” Harrison, director of WMU’s core research laboratory, described the lithologic properties and facies characteristics of the major hydrocarbon producing formation in the Michigan Basin. Illustrative cores were on hand for attendees to see for themselves. Importantly, Harrison described the resources available in the core research lab, noting that lots of data were available online at www.wmich.edu/geology/corelab/corelab.htm.

John Repetski of the USGS illustrated how conodont color alteration index (CAI) maps, using a Devonian CAI map as an example, could be helpful in:

• Identifying areas of favorable or unfavorable thermal regimes for in-place hydrocarbon generation/preservation;

• Determining and constraining the basin’s burial history and thermal evolution; and

• Solving stratigraphic problems.

Conodonts are mineralized hard parts (teeth) of an extinct marine animal group. They occur in most marine environments; are excellent biostratigraphic zonal indicators; can be easily extracted from many rock types, including cuttings; and age determination is not difficult or expensive. To put it simply, conodont analysis is a reliable, quick, low-cost approach that provides answers to important exploration questions.

Daniel Hayba with the USGS highlighted key points from the agency’s thermal evolution study. The subsidence, sedimentation and uplift of the Michigan Basin reflect the tectonic events of the Appalachians. A 2-D model requires laterally variable lithologic input. Extreme Late Silurian deposition and Early Devonian uplift and erosion are unlikely. The basin was buried 1,000-3,000 feet deeper than at present. Heat flow was higher along the southern margin during maximum burial. Higher heat flow related to fluid migration driven by Alleghanian orogeny. Timing of source rock maturation is related to orogenic events.

Carbon dioxide-enhanced oil recovery represents an opportunity to get technically recoverable oil that has already been found. Three Niagaran (Middle Silurian) reef reservoirs in Otsego County, Mi., have been converted to CO₂ injection floods (Dover 33, Dover 35 and Dover 36 in T31N, R2W). Dover 33 and 36 were developed in 1996, and operations continue. Dover 35 is a relatively new project started in early 2004. CO₂ comes from a nearby Antrim gas processing plant. More than 300,000 tons of CO₂ have been injected, and there has been 750,000 barrels of enhanced oil recovery in nine years. There is lots more CO₂ from the Antrim that could be beneficially applied, and the targets abound–there are more than 700 reefs in northern Michigan.