Taglu Gas Field, Beaufort Basin, Northwest Territories1
The Taglu gas field, discovered in 1971, is located near the outer fringe of the Mackenzie River delta, in the south-central part of the Beaufort Tertiary basin. Four wells and available seismic lines currently define about 12 sq mi (31 km2) of productive area within a structural closure. The gas occurs in lower Tertiary sandstone reservoirs on the updip edge of a rotated down-to-basin fault block.
The basin is filled by a deltaic clastic sequence of sandstone and shale; deposition, which prograded northward, began in Late Cretaceous time and is continuing today at the shelf edge.
The southeast margin of the basin lies along the Tuk Peninsula. There, the Tertiary sediments prograded across a linear block-faulted hinge line formed of Lower Cretaceous transgressive sandstone and shale sequences overlying Paleozoic and older beds. Within the Lower Cretaceous beds, complex faulting and reservoir distribution control the hydrocarbon “play” that has yielded oil at Atkinson and gas at Parsons Lake.
The southwest margin of the basin lies along the locally designated “West coastal plain” (Yukon or Arctic coastal plain) where a thick Jurassic—Lower Cretaceous sedimentary section accumulated in front of a rising mountain belt. Only a small portion of the Tertiary-Cretaceous basin extends onto the onshore part of this southwest margin.
Offshore, the younger strata thicken abruptly into Mackenzie Bay and the Beaufort Sea.
During Tertiary time, the rapidly deposited, prograded sediments in the basin became involved in a partly gravity-induced, detached style of structural deformation. This deformation, which contrasts with the high-angle, basement-involved block faulting of the margins, has created diapirlike, shale-cored structures and growth faults. The association of these structures with prospective reservoir sequences has resulted in the style of hydrocarbon accumulation represented by the Taglu gas field.
Associated with sedimentation and deformation of this type is the phenomenon of overpressure, which has been encountered in most wells in the Mackenzie River delta. It is caused by undercompaction of fine-grained impermeable sediments, whereby pore waters are unable to escape and must support part of the weight of overburden.
Organic material within the Beaufort Tertiary strata has a predominantly terrestrial character. This fact, combined with low maturation levels, probably accounts for the predominance of gas and condensate discovered to date in the Beaufort Tertiary basin.
In the Taglu field, gas is produced from multiple sandstone reservoirs, probably of Eocene age, in a 1,700-ft (518 m) stratigraphic delta-front sequence below 7,700 ft (2,347 m). Gas columns of up to 1,700 ft (518 m) fill the closure almost to the spillpoint. The gas is usually wet and consists of 91-96 percent methane and 4-9 percent heavy hydrocarbons (C2+), with no hydrogen sulfide. Wet-gas reserves are estimated to be in excess of 3 Tcf.
About 75 percent of the Taglu gas reservoirs consists of beach and stream-mouth bar sandstones; distributary-channel sandstones make up approximately 15 percent and shoreface sandstones about 10 percent. Net sandstone thicknesses in the wells range from about 450 to 600 ft (135-185 m).
The abundant, organic-rich, delta-front shales interbedded with the reservoir sandstones are the most likely source of the hydrocarbons. Therefore, a relatively small drainage area is required. An immature woody material, possibly with some biodegradation, is indicated as the hydrocarbon source by the relatively high aromatic content of the associated condensates.
The condensates have API gravities ranging from 33 to 48°, and a very low sulfur content. Oil gravities range from 17 to 32° API. Pour points range from +45ºF (+7.22ºC) in a paraffinic oil to –55ºF (–48.33ºC) in a naphthenic oil. The low gravity and pour point of some of the oils may be due to biodegradation which removed paraffins by bacterial action.