The Thomson Oil Pool encompasses the early Cretaceous-aged (Neocomian)13
Thomson Sand, a conglomeratic sandstone that measures about 12 miles long, 5 miles wide, and ranges up to 330 - 350 feet thick in the Point Thomson area.14
It is stratigraphically equivalent to the Kemik Sandstone that is located approximately 30 miles to the south.15
The Thomson Sand consists of very fine- to very coarse-grained, dolomite-rich sandstone that contains argillaceous rock fragments. Dolomite-rich pebble-, cobble- and boulder-conglomerates are locally abundant.16
The abundance of coarse, dolomite clasts and close association with an erosional unconformity suggest a local source for the Thomson Sand.17
The sediments that comprise the Thomson Sand reservoir were derived from basement rocks that were exposed in the northern and northeastern portions of the Point Thomson Field and bordered to the southwest by a sea. Eroded sediments were transported down-gradient toward the southwest and progressively deposited in alluvial fan, fan-delta, and marine shoreface environments. Wave and current activity extensively reworked these sediments and distributed them in southeast-trending bands arranged subparallel to the shoreline. From northeast (proximal) to southwest (distal), these bands generally consist of alluvial fan breccia, conglomerate, conglomerate with minor sandstone, sandstone, silty sandstone, and siltstone. In general, coarser-grained, proximal lithologies are dominated by carbonate clasts, with quartz and ductile grains becoming increasingly prominent in the more distal areas that lie to the southwest.18
ExxonMobil informally divides the Thomson Sand into an upper member and a lower member based on core descriptions and well log correlations. The lower member is dominantly progradational, whereas the upper member is dominantly retrogradational.19
The Thomson Sand is unconformably overlain by siltstone, mudstone, and shale assigned to the Canning Formation, Hue Shale, and HRZ, in descending stratigraphic order. Erosion thinned the Hue and HRZ shale intervals toward the northeast, and completely removed these intervals from the northern and eastern portions of the PTU.
The structure of the proposed Thomson Oil Pool is a gently dipping, four-way anticlinal closure. Based on well and 3D-seismic control, the top of the pool lies about -12,500 feet TVDSS, and the structure extends to a depth of about -14,500 feet TVDSS within the PTU area. The Thomson anticlinal closure is cut by several, north- and north-northeast-trending, normal faults. The vertical displacement of faults observed within the Thomson Sand interval averages about 65 to 95 feet, with a maximum of about 200’, but none of these faults appear to completely displace the Thomson Sand or create isolated compartments within it. None of the faults are expected to act as flow barriers.
Well log and seismic information indicate that hydrocarbon distribution within the proposed Thomson Oil Pool is influenced by both structural and stratigraphic elements. The broad, east-southeast-trending anticlinal closure provides primary control for the accumulation. Internal facies changes within the Thomson Sand interval strongly influence reservoir quality and the distribution of hydrocarbons, especially in the southern and western portions of the PTU.
The Thomson Sand is overlain by a thick, laterally extensive section of siltstone, mudstone, and shale assigned, in descending stratigraphic order, to the Canning Formation, Hue Shale, and HRZ Shale. These intervals provide the top seal for the proposed Thomson Oil Pool. In the northern and northeastern parts of the PTU, where the Hue and HRZ intervals are either absent or are very thin, mudstone and siltstone assigned to the lower Canning Formation provides a top seal.20
The Thomson Sand is underlain predominantly by thick Pre-Mississippian-aged dolomite, phyllite, and quartzite basement rocks.21
Fractured and/or karsted dolomite appears restricted to the northern part of the field, and this rock may serve as a secondary reservoir in communication with the Thomson Sand.22,23
Within the Point Thomson Field, the accumulation within the Thomson Sand comprises a nearly 500-foot thick, high-pressure, condensate-gas “cap” (gas cap) and an underlying, 37-foot thick rim of viscous oil. Relict oil saturation exists within the gas cap due to multiple oil migration events. Relict oil saturation increases downward, toward the gas-oil contact. Average oil saturation within the gas cap is approximately 10%. Condensate yield for the reservoir is estimated to be about 60 to 65 stock tank barrels (stb) per 1 million standard cubic feet of gas (MMSCF). Flow tests and reservoir pressure measurements indicate that the Thomson Oil Pool is not separated into isolated compartments within the Affected Area.24
The oil rim consists of 10° to 18° API gravity oil that has a viscosity of about two centipoise at reservoir conditions. The lower portion of the oil rim consists of an oil-water transition zone, where both oil and water are partially mobile.25
The Thomson Oil Pool is abnormally geo-pressured: average reservoir pressure is about 10,100 psi at ExxonMobil’s specified pressure datum of -12,700 feet TVDSS (a pore-pressure gradient of about 0.795 psi/ft). Abnormal fluid pressure gradients as high as 0.84 psi per foot, have been reported for the basement rocks, Thomson Sand, pebble shale, Hue Shale, and lower Canning Formation (in ascending order).26,27
Reservoir temperature ranges from about 220° to 230° F.28
Other potential secondary reservoirs in the Point Thomson area are marine sandstones29
of the Cretaceous- to Oligocene-aged Canning Formation, which have produced oil and gas during well tests.30