St. Lawrence Platform – Economic Geology

Sanford, B. V.

doi:10.1130/dnag-gna-d1.787

Cited by 5 publications

(3 citation statements)

References 2 publications

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“…The Mingan Formation (Darriwilian to Caradocian) consists of limestones and dolomitic limestones, with minor shales and sandstones. The Macasty Formation and the lower part of the Vauréal Formation (late Caradocian to early Ashgillian) are mainly composed of shales with minor sandstones, whereas the upper part of the Vauréal Formation, the Ellis Bay Formation, and the Anticosti Group (Ashgillian to Llandoverian) are composed of limestones with minor shales and sandstones (Bertrand 1987; Sanford 1993).…”

Section: Geologic Settingmentioning

confidence: 99%

“…The Anticosti Basin is part of the St. Lawrence Platform developed along the Paleozoic Laurentia continental margin (Sanford 1993). It consists of two sedimentary packages: a Cambrian to Lower Ordovician passive margin succession and a Middle Ordovician to Lower Devonian foreland basin succession (Waldron et al.…”

Section: Geologic Settingmentioning

confidence: 99%

“… (A) Regional geologic map of part of eastern Canada (simplified from Sanford 1993; Williams 1995). The dashed line is the Appalachian Structural Front.…”

Section: Introductionmentioning

confidence: 99%

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Downward hydrocarbon migration predicted from numerical modeling of fluid overpressure in the Paleozoic Anticosti Basin, eastern Canada

et al. 2010

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The Anticosti Basin is a large Paleozoic basin in eastern Canada where potential source and reservoir rocks have been identified but no economic hydrocarbon reservoirs have been found. Potential source rocks of the Upper Ordovician Macasty Formation overlie carbonates of the Middle Ordovician Mingan Formation, which are underlain by dolostones of the Lower Ordovician Romaine Formation. These carbonates have been subjected to dissolution and dolomitization and are potential hydrocarbon reservoirs. Numerical simulations of fluid-overpressure development related to sediment compaction and hydrocarbon generation were carried out to investigate whether hydrocarbons generated in the Macasty Formation could migrate downward into the underlying Mingan and Romaine formations. The modeling results indicate that, in the central part of the basin, maximum fluid overpressures developed above the Macasty Formation due to rapid sedimentation. This overpressured core dissipated gradually with time, but the overpressure pattern (i.e. maximum overpressure above source rock) was maintained during the generation of oil and gas. The downward impelling force associated with fluid-overpressure gradients in the central part of the basin was stronger than the buoyancy force for oil, whereas the buoyancy force for gas and for oil generated in the later stage of the basin is stronger than the overpressure-related force. Based on these results, it is proposed that oil generated from the Macasty Formation in the central part of the basin first moved downward into the Mingan and Romaine formations, and then migrated laterally up-dip toward the basin margin, whereas gas throughout the basin and oil generated in the northern part of the basin generally moved upward. Consequently, gas reservoirs are predicted to occur in the upper part of the basin, whereas oil reservoirs are more likely to be found in the strata below the source rocks.

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Section: Geologic Settingmentioning

confidence: 99%

Section: Geologic Settingmentioning

confidence: 99%

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Downward hydrocarbon migration predicted from numerical modeling of fluid overpressure in the Paleozoic Anticosti Basin, eastern Canada

et al. 2010

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The Marcellus Shale Play: Its Discovery and Emergence as a Major Global Hydrocarbon Accumulation

Zagórski¹,

Emery²,

Ventura³

2017

Giant Fields of the Decade 2000–2010

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The Middle Devonian Marcellus shale play has emerged as a major world-class hydrocarbon accumulation. It has rapidly evolved into a major shale gas target in North America and represents one of the largest and most prolific shale plays in the world with a prospective area of approximately 114,000 km2 (44,000 mi2). Two major core areas have emerged, each with a unique combination of controlling geologic factors. Production from the Marcellus play reached 16 billion cubic feet of gas equivalent per day (BCFepd) in 2015, and it has been recognized as the largest producing gas field in the United States since 2012. The organic-rich black shales comprising the Marcellus shale were deposited in a foreland basin that roughly parallels the present-day Allegheny structural front. The Marcellus shale accumulated within an environment favorable to the production, deposition, and preservation of organic-rich sediments. The key geologic and technical factors that regionally define the Marcellus play core areas include organic richness, thermal maturity, degree of overpressure, pay thickness, porosity, permeability, gas in place, degree of natural fracturing, mineralogy, depth, structural style, lateral target selection, completion design, and important rock mechanics issues such as the ability to be fractured, rock brittleness versus ductility, and the ability to generate complex fractures. Structural setting and deformation styles are critical to address natural fracture trends, potential geologic hazards such as faulting and fracturing in structurally complex areas, and fracture stimulation containment issues. Since the Marcellus shale unconventional shale gas reservoir discovery in 2004 until May 2015, more than 8600 horizontal Marcellus shale wells had been drilled in Pennsylvania, West Virginia, and limited portions of eastern Ohio. Many decades of future drilling potential remain due to the enormous extent of the Marcellus shale play. Horizontal Marcellus wells report initial production rates ranging from less than 1 MMCFe/day to over 47.6 MMCFe/day. Despite the large number of wells drilled and completed to date and production of 16 BCFepd in 2015, the play is still in its infancy due to its vast geographic extent and production potential. The Marcellus shale represents a continuous-type gas accumulation and when fully developed will comprise a large continuous field or series of fields. Over its productive trend, the Marcellus shale play has significant additional reserve potential in the overlying organic shales in the Devonian Age Rhinestreet, Geneseo, and Burket units as well as deeper potential in the Ordovician Age Utica/Point Pleasant units. Estimates of recoverable reserves from the world’s largest gas fields combine their reserve estimates for all key productive units in the field/play trend. Likewise, estimates of in-place gas resources for the Marcellus play range from 2322 tcf for the Marcellus (Hamilton Group) to over 3698 tcf for the combined Devonian Age Marcellus-Geneseo-Rhinestreet system. This represents the largest technically accessible in-place gas resources in the world.

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Assessment of Appalachian basin oil and gas resources: Devonian shale— Middle and Upper Paleozoic Total Petroleum System

Milici¹,

Swezey²

2006

Open-File Report

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St. Lawrence Platform – Economic Geology

Cited by 5 publications

References 2 publications

Downward hydrocarbon migration predicted from numerical modeling of fluid overpressure in the Paleozoic Anticosti Basin, eastern Canada

Downward hydrocarbon migration predicted from numerical modeling of fluid overpressure in the Paleozoic Anticosti Basin, eastern Canada

The Marcellus Shale Play: Its Discovery and Emergence as a Major Global Hydrocarbon Accumulation

Assessment of Appalachian basin oil and gas resources: Devonian shale— Middle and Upper Paleozoic Total Petroleum System

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