Australia's sandstone-hosted uranium deposits occur in sedimentary basins of Carboniferous, Cretaceous and Tertiary age; these include some of Australia's largest and highest grade uranium deposits. The conventional model for sandstone-hosted uranium deposits has proved robust and a predictive model leading to the discovery of many deposits in Australia. The location of deposits is strongly influenced by the presence of Mesoproterozoic and Archaean age leachable uraniumrich source rocks in the headwaters of channels draining into basins developed in the Northern Territory, Western Australia and South Australia. Australia's production of uranium from sandstone-hosted deposits is limited to two in-situ leach operations and is relatively minor when compared to production from Kazakhstan and the USA. Nevertheless, Australia has a large inventory of uranium resources in 19 undeveloped sandstone-hosted deposits, amounting to 123 kt U 3 O 8 . The average grade of all 21 Australian deposits that have resources is 0?15% U 3 O 8 . Tertiary palaeochannels host the greatest number of deposits and include the largest and highest grade deposits. The Callabonna Sub-basin in South Australia is the most richly endowed basin, accounting for 62?4 kt U 3 O 8 , being 38% of Australia's sandstone-hosted resource inventory. Australia remains highly prospective for the discovery of new palaeochannel hosted uranium deposits, with regional airborne geophysical surveys likely to be of great assistance in continuing to define palaeochannel systems that may host uranium in basins draining uranium rich source rocks.

Deep basin hydrocarbon accumulations have been widely recognised in North America and include the giant fields of Elmworth and Hoadley in the Western Canadian Basin. Deep basin accumulations are unconventional, being located downdip of water-saturated rocks, with no obvious impermeable barrier separating them. Gas accumulations in the Nappamerri Trough, Cooper Basin, exhibit several characteristics consistent with North American deep basin accumulations. Log evaluation suggests thick gas columns and tests have recovered only gas and no water. The resistivity of the entire rock section exceeds 20 Ωm over large intervals, and, as in known deep basin accumulations, the entire rock section may contain gas. Gas in the Nappamerri Trough is located within overpressured compartments which witness the hydraulic isolation necessary for gas saturation outside conventional closure. Furthermore, the Nappamerri Trough, like known deep basin accumulations, has extensive, coal-rich source rocks capable of generating enormous hydrocarbon volumes. The above evidence for a deep basin-type gas accumulation in the Nappamerri Trough is necessarily circumstantial, and the existence of a deep gas accumulation can only be proven unequivocally by drilling wells outside conventional closure.Exploration for deep basin-type accumulations should focus on depositional-structural-diagenetic sweet spots (DSDS), irrespective of conventional closure. This is of particular significance for a potential Nappamerri Trough deep basin accumulation because depositional models suggest that the best net/gross may be in structural lows, inherited from syndepositional lows, that host stacked channel sands within channel belt systems. Limiting exploration to conventionally-trapped gas may preclude intersection with such sweet spots.

The continuous movement of ground water in sandstone hosted uranium deposits renders them subject to disequilibrium between uranium and its daughter products. This is important when wireline gamma logging alone is used to quantify the presence of uranium which can be over-or under-estimated by a significant percentage. The problem can be overcome by logging using the prompt fission neutron (PFN) tool which directly measures the presence of uranium through neutron activation. PFN technology is also superior to core drilling and assay as it provides a larger sample, is less expensive and is instantaneous, allowing drilling programs to proceed uninterrupted. Examples are presented from uranium deposits in Australia and the USA demonstrating disequilibrium, and the use of PFN to map uranium throughout a deposit and to set the screens in in situ leach mining.

Gas Oil Gravity Drainage (GOGD) of the Qarn Alam fractured low permeability carbonate reservoir is being enhanced by steam injection in the world's first full field development carbonate thermal development. Unlike a normal steam flood, the steam is used as a heating agent to enhance the existing gravity drainage mechanisms, and project has proved to be viable based on encouraging pilot results. The elegance of the thermally assisted - GOGD is that the fracture network is both used for distribution of steam and recovery of the oil. The number of wells can therefore be kept to a minimum compared to conventional matrix steam floods. Whereas the primary production performance of the Qarn Alam under cold GOGD is only expected to recover 3–5 % of the oil in place, studies to date indicate that the recovery factor under steam injection at 18,000 tonne per day will be in the range 20–35 % with Oil Steam Ratio of 0.16 -0.3 m3 oil /tonne of steam. The learning from the Pilot has not only helped understand the subsurface uncertainties but also provided significant insight into the engineering design and operational issues which are being managed right upfront during design. Energy consumption in the full field development of this project is reduced by banking on the benefit from co-generation of power and steam. Utilisation of co-generation will minimise CO2 emission and reduce gas import. The project will be under construction from 2007, with full rate steam injection reached by late 2009. The paper not only discusses how the project addresses the reservoir management challenges of this complex recovery mechanism but will address some of the engineering and operational challenges that are being managed. Introduction Qarn Alam Field is located in central Oman south of the western Hajar Mountains. This large oil accumulation is trapped in shallow Cretaceouslimestone units at a depth of around 200–400m sub sea. The anti-clinal structure is a result of a deep salt diaper, with significant crestal faulting and fracturing. The field was discovered in 1972 and placed on primary production in 1975. The 16° API oil with a viscosity of 220cP has been produced from the 29% porosity, low permeability (5–14mD) limestone. . During the primary production period from 1975 to 1995, the first year showed a large peak in oil mainly from emptying of the fracture network with a minor contribution from fluid expansion due to pressure reduction. At the end of the first year, production had declined to a very low sustainable rate interpreted to be from gravity drainage, from a combination of gas-oil (GOGD) from the secondary gas cap and oil-water (OWGD) below the fracture gas-oil contact (FGOC). The reservoir then consists of a matrix with very little drainage and a fracture network with a thin oil rim below the secondary gas cap and above the fracture oil-water contact (FOWC), figure 1. Primary production performance such as that of Qarn Alam is only expected to recover some 3–5% of the oil in place over any reasonable time frame due to low matrix permeability and high oil viscosity on gravity drainage rates. Recoveries via matrix floods of water, polymer or steam were discounted as development options due to the pervasive fracturing observed in the field which would encourage the flooding agents to completely bypass the matrix.

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