EXPLORING APPALACHIA'S MIDDLE ORDOVICIAN CARBONATES

Based on a workshop co- sponsored by PTTC's Appalachian Region and the Appalachian Oil and Natural Gas Research Consortium on November 11, 1999 in Morgantown, WV

BOTTOM LINE

The real extent of the Ordovician Trenton-Black River Group in the Appalachian Basin is large. Acquiring and communicating to regional producers a working knowledge of the conditions under which success has already been achieved could substantially enhance commercial production. 

PROBLEM ADDRESSED

Producers are continually looking for cost-effective approaches to reduce exploration and development risks— from pursuing leads and prospects to high-grading leases to assessing reservoir compartmentalization. When combined with subsurface geological and geophysical information, surface exploration methods can reduce risk. Importantly, they can verify the presence of hydrocarbons. Surface expression of hydrocarbon seepage takes many forms, which has led to the development of many surface exploration methods. The most successful methods are based on direct detection of hydrocarbons or hydrocarbon-induced alteration anomalies.

KEY WORDS:

Basement faults, Completion strategies, Dual porosity, Fracture porosity, Tight gas, Trenton- Black River Group

SPEAKERS

Appalachian Basin Development History/ Fracture Models
Robert Shumaker, West Virginia University

Completion and Stimulation Strategies
Roger Meyers, BJ Services Co., USA

Trenton-Black River in Ohio
Larry Wickstrom, Ohio Division of Geological Survey

Trenton-Black River in New York
Ed Berg, Thomasson Partner Associates, Inc.

Trenton-Black River in Newfoundland and Quebec
Mark Cooper, PanCanadian Petroleum Ltd.

TECHNOLOGY OVERVIEW

Two Precambrian plate tectonic cycles contributed their structural overprints to the Appalachian Basin before deposition of the Ordovician Trenton-Black River sediments. Broad sag basins had formed over the rift features of the latest of these cycles during the early Paleozoic period. During the Ordovician, the Appalachian Basin became the archetypal geosyncline, a foreland trough formed by subduction, loading, and collision along the plate margin. The Central Appalachian segment of the foreland was broader than the segments to both the north and the south, and a structural hinge located in West Virginia separated the Appalachian Basin proper to the west from the foreland trough to the east.

Middle Ordovician Trenton and Black River limestones were deposited as an eastward sloping ramp that thickened into the rapidly subsiding deep foreland trough. Limestone deposition, most often under anaerobic deep-water conditions, was accompanied by periodic large influxes of shale. As plate convergence continued to uplift the source area, the terrigenous components eventually overwhelmed carbonate deposition and flysch deposits continued to fill the trough.

In the Appalachian Basin, attention has traditionally focused on black shales of Devonian to Mississippian age as potential source rocks, but Ordovician black shales deposited in association with the limestones of the Trenton-Black River Group also have great potential. Kerogens are aliphatic, probably of algal origin, and were initially oil-prone. In the southeastern part of the basin, shales reach aggregate thicknesses of up to 5,000 feet with time-temperature indexes that indicate dry gas generation. To the north and east, kerogens have probably passed through the oil window completely and are well into the metagenic gas generation stage of maturity. Westward into Ohio, lower maturity values indicate that kerogens may have potential for continued oil generation.

Historically, production of natural gas in the Appalachian Basin has been from the west side of the basin, but we are now seeing substantial commercial production established in association with faults from Trenton-Black River carbonates.

In Ohio, Trenton-Black River limestones and the Utica Shale, which lies stratigraphically above the Trenton-Black River Group, are productive. These formations do not normally sustain a rate of production to justify them as primary drilling targets, but they are often attractive add-ons and typically produce over a long period of time. Predicting producibility in offset wells is difficult. A discovery well drilled in 1977 producing from the Middle Ordovician in association with a large fault in Ashtabula County has produced more than 500 million cubic feet of gas and 2,000 barrels of oil. Several additional productive wells have been drilled into this feature.

The importance of fault association with development of producibility is emphasized by an example from Western Newfoundland. A recent well tested oil in association with complex extensional faults that served as permeability pathways to admit dolomitizing and karsting fluids during a period of subaerial exposure in the Middle Ordovician. In southwest Ontario, oil and gas reservoirs of the TrentonBlack River Group are responsible for more than 75% of the province's production.

In New York, regional seismic, subsurface data, and aeromagnetic surveys identify deep-seated, basement-involved fault trends responsible for Trenton-Black river production. Early Devonian reactivation of these faults led to porosity development similar to that at the 150 million barrel Albion-Scipio field in Michigan. Potential prospects, initially identified as intersecting linears with filtered aeromagnetic data, are further defined with seismic and other data. Important seismic criteria include:

• Anomalous increase or decrease of the top-Trenton reflection amplitude
• Decrease in reflection continuity at the top of, and with in, the Trenton-Black River
• Zones of seismic noise above, below, and within the Trenton
• A sag in the top-Trenton reflection accompanied by thickening of overlying units Locating fracture porosity is recognized as an important exploration step in these tight sedimentary rocks. In many instances, production has been the result of reactivation of older basement faults by strike-slip movement. A minishort-course on strike-slip fracture models was therefore an informative part of the workshop.

Fractures consist of joints and faults that may be looked at on a regional as well as a local scale. Regional joint patterns formed mostly during Paleozoic orogeny and, although they may enhance producibility to some extent, are not dense enough in their distribution to guarantee commercial production (except perhaps in some Devonian shales). Most of the production from the Trenton-Black River Group in the Appalachian Basin is from fractures caused by reactivation of basement faults that not only re-opened previous fracture porosity but also introduced diagenetic fluids in many instances that increased matrix porosity as well. Dolomitized, fractured reservoirs along vertical faults are often kilometers in length, but only hundreds of meters in width. Such reservoirs are often accompanied by structural depressions above the dolomitized zones.

Additional critical presentations at the workshop covered the development of completion strategies for Trenton-Black River reservoirs. Included were determination of important reservoir properties, such as matrix porosity and permeability, fracture orientation and density using borehole imaging tools, soluble and insoluble components and other formation damage mechanisms, in-situ stresses, and pore pressure. This information allows selection of appropriate cased or openhole completion and stimulation techniques. One of three primary completion methods seems to fit most situations: openhole, perforated cased hole using near-wellbore acid for damage clean-up, or perforated cased hole using fracture extension (good for tight dolomites). Specific completion case histories were presented for wells in West Virginia, Ohio, New York, and Michigan.

LESSONS LEARNED

Complex patterns of fracturing may be introduced by numerous episodes of fault reactivation under regional and local stress fields of different orientation. In addition, shear fracture type is often difficult to identify in wellbores. Both these factors suggest caution in use of fracture orientation as observed in wells to predict optimum stepout direction.

CONNECTIONS:

Robert Shumaker,
Department of Geology and Geography West Virginia University,
P. O. Box 6300 Morgantown, WV 26506
Phone: 304-293-5603x4307, Fax 304-293-6522 E-mail rshumake@wvu.edu

Roger Meyers,
BJ Services Co., USA
Penn Center West IV, Suite 102,
Pittsburgh, PA 15276-0104
Phone: 412-494-3312, Fax 412-494-3318 E-mail rmeyers@bjservices.com

Lawrence Wickstrom,
Ohio Division of Geological Survey
4383 Fountain Square Drive,
Columbus, OH 43224
Phone: 614-265-6598, Fax 614-447-1918 E-mail larry.wickstrom@dnr.state.oh.us

Ed Berg,
Thomasson Partner Associates, Inc.
1100 Stout St., Suite 1400,
Denver, CO 80204
Phone: 303-436-1930 Fax 303-436-1935

For information on PTTC’s Appalachian region and its activities contact:
Douglas Patchen, Program Director,
Appalachian Oil & Natural Gas Research Consortium West Virginia University,
NRCCE-Evansdale Dr., PO Box 6064 Morgantown, WV 26506-6064
Phone: 304-293-2867 x-5443, Fax 304-293-7822, E-mail dpatch@wvunrcce.nrcce.wvu.edu

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