--> Abstract: Fluvial Stratigraphic Architecture of the Jurassic Monach Formation, Northwest Alberta, Canada: Implications for Tight Gas Reservoir Delineation, by Ross Kukulski, Stephen M. Hubbard, Keegan M. Raines, and Thomas Moslow; #90124 (2011)

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AAPG ANNUAL CONFERENCE AND EXHIBITION
Making the Next Giant Leap in Geosciences
April 10-13, 2011, Houston, Texas, USA

Fluvial Stratigraphic Architecture of the Jurassic Monach Formation, Northwest Alberta, Canada: Implications for Tight Gas Reservoir Delineation

Ross Kukulski1; Stephen M. Hubbard1; Keegan M. Raines1; Thomas Moslow2

(1) Geoscience, University of Calgary, Calgary, AB, Canada.

(2) Pace Oil & Gas, Calgary, AB, Canada.

Laterally extensive fluvial sandstones of the Jurassic Monach Formation (Nikanassin Group) represent an unconventional tight gas reservoir target in the Deep Basin of NW Alberta. The tectonostratigraphically significant strata have been understudied and its emergence as a viable resource play has driven new research into its origin, distribution and rock properties. Traditionally, the Monach Formation has been relegated to a secondary gas target due to limited reservoir quality (Porosity = 3-9%, Permeability = <0.1-1.0 md), significant drilling costs due to depth (2500-4000 m) and limited exploration success. Recently, improvements in drilling and completions technology (i.e. horizontal drilling and massive hydraulic fracturing), coupled with geological work recognizing the role played by natural fractures in enhancing permeability, have yielded significant increases in production resulting in the Monach Formation emerging as a primary drilling target.

As is the case for all fluvial reservoir targets, sedimentologic heterogeneity and stratigraphic complexity have a significant impact on reservoir quality and deliverability. Interpreting the Monach Formation stratigraphic architecture is additionally complicated by poor seismic resolution, limited well penetrations, and differential erosion associated with an overlying angular unconformity. Despite these challenges, insight into reservoir distribution are derived from detailed sedimentological, petrophysical and petrographical analyses of the strata from outcrop, >1000 wells, and 30 full diameter cores.

Paleoflow measurements from outcrop and regional sandstone distribution trends indicate a northeastern sediment transport direction and a western source area. Regionally, net sandstone thicknesses and degree of channel amalgamation vary predictably both vertically and laterally throughout the basin allowing for a stratigraphic division characterized by a lower zone with large more amalgamated sandstone bodies and an upper zone with small less amalgamated sandstone bodies. Over 400 cross-bed thicknesses were measured from cores and outcrop in order to estimate maximum channel belt depths (4.1-18.3 m) and widths (514-3992 m) and to provide insight into local correlations. Applying these results allows for a more detailed stratigraphic framework to be developed within a limited dataset and sets the stage for improved exploration strategies to be employed for this economically significant deposit.