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Sedimentology, diagenesis and reservoir development of the lower triassic montney formation, northeastern British Columbia Nassichuk, Brent Ronald

Abstract

The Lower Triassic Montney Formation in northeastern British Columbia (NEBC) includes a thick succession (up to 260 m) of turbidite and deltaic strata that are important reservoir rocks. The succession was deposited from the distal shelf to foreshore. Discovery of gas reservoir rocks from turbidite and deltaic intervals has led to production in the Kahntah, Ring-Border and Chinchaga Fields. The Montney Formation in NEBC comprises seven lithofacies consisting of aeolian-sourced very fine-grained sandstones, siltstones and rare mudstone intervals. The lithofacies are represented by three facies associations that record deposition within the distal shelf, proximal shelf and foreshore. The distal shelf consists of parallel laminated siltstone and sandstone, derived from low-density turbidity currents. Coarser grained turbidite lobe deposits, locally incised turbidite channels and tempestites dominate the proximal shelf. The foreshore is host to bioturbated, tidally influenced delta front sand sheets. Reservoir lithofacies occur within the proximal shelf turbidites and the foreshore deltaic intervals. Producing intervals consist primarily of very fine-grained sandstone and siltstone. Throughout the Montney Formation, sediments record evidence for seismic activity. Seismites include highly sheared and fractured very fine-grained sandstone and siltstone. Tectonically influenced sediments are interpreted to represent uplift on the northwest side of the Hay River Fault Zone (HRFZ). Fault motion during the Early Triassic is interpreted as. The fault motion promoted the deposition of foreshore deltaic sediments onto proximal shelf turbidites. Production rates within the reservoir intervals is controlled by lithology and diagenesis. The very fine-grained nature of the Montney Formation has low to moderate permeability, suitable for gas storage. Turbidite reservoirs average about 13% porosity and 6 mD permeability while deltaic reservoirs average 12.5% porosity and 4 mD permeability. Porosity within the Montney Formation of NEBC consists of remnant intergranular primary porosity and enhanced secondary porosity due to dissolution of ferroan dolomite cement. Mercury porosimetry was used to determine capillary pressure curves for each of the lithofacies. Breakthrough pressures show how much force must be exerted to create a connected pathway of mercury through the sample. Lithofacies requiring high breakthrough pressures possess low reservoir potential. Very fine-grained turbidite and deltaic intervals have the lowest breakthrough pressures. Further exploration in the Montney Formation of NEBC may be enhanced by considering the depositional model and diagenetic trends. The thickest turbidite accumulations occur within paleo-lows of the underlying Paleozoic surface. Unexplored turbidite pathways exist in the southern portion of the study area. An increase in secondary porosity occurs from north to south in the study area, indicating high reservoir potential in the south.

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