Abstract

The Taglu gas field is located in the south central area of the Beaufort Tertiary Basin, in Lower Tertiary sandstone reservoirs, on the updip edge of a rotated down-to-basin fault block.

The basin was filled by a northerly progradation of deltaic clastics that began in Late Cretaceous time and is continuing today at the shelf edge.

The southeast margin of the basin lies along the Tuktoyaktuk Peninsula. There, the Tertiary clastics prograded across a linear block-faulted hingeline comprising a Lower Cretaceous transgressive clastic series overlying Paleozoic and older beds. Within the Lower Cretaceous rocks complex faulting and reservoir distribution control a hydrocarbon play that has yielded oil at Atkinson Point and gas at Parsons Lake.

The southwest margin of the basin is developed along the west Coastal Plain where a thick Jurassic-Lower Cretaceous lithic section accumulated in front of a rising mountain belt.

Only a small portion of the Tertiary-Cretaceous basin extends into the onshore part of the southwest margin. Offshore the younger sediments thicken rapidly into Mackenzie Bay and the Beaufort Sea.

In the Tertiary basin, the rapidly deposited prograded sediments became involved in a partly gravity-induced, detached style of deformation. These dislocations contrast with the high angle, basement-involved block-faults of the margins, and created diapir-like, shale-cored structures and growth faults.

The association of these structures with prospective reservoir sequences has resulted in the style of hydrocarbon play of which Taglu is representative.

Associated with a play of this type is the phenomenon of over-pressure. It is caused by undercompaction of fine-grained, impermeable sediments, where pore waters are unable to escape, and which support part of the weight of overburden. This pressure is released when penetrated by a borehole. It has been encountered to some degree in most delta wells.

Source material within the Beaufort Tertiary sediments has a predominantly terrestrial character. This, combined with low maturation levels, probably accounts for the predominance of gas and condensate recovered to date from the Beaufort Tertiary basin.

The gas is usually wet, with 91 to 96 per cent methane, and 4 to 9 per cent heavy hydrocarbons (C₂ + ). It is sweet, with no H₂S. The associated condensates have API gravities ranging from 33° to 48° and have a very low sulphur content.

Oil gravities range from 17° to 32° API. Pour points range from +45° in a paraffinic oil to -55°F in a naphthenic oil. The low gravity and low pour point in some oils may be due to biodegradation which removed paraffins by bacterial action.