The Sunrise and Troubadour fields form a complex of giant gas-condensate accumulations located in the Timor Sea some 450 km northwest of Darwin. Left unappraised for almost a quarter of a century since discovery, recently renewed attention has brought these stranded hydrocarbon accumulations to the point of comm-ercialisation.A focussed appraisal program during 1997–1999 driven by expectations of growth in LNG and domestic gas markets, involved the acquisition and processing of an extensive grid of modern 2D seismic and the drilling, coring and testing of three wells. The aim of this program was to quantify better both in-place hydrocarbon volumes (reservoir properties and their distribution) and hydrocarbon recovery efficiency (gas quality and deliverability). Maximum value has been extracted from these data via a combination of deterministic and probabilistic methods, and the integration of analyses across all disciplines.This paper provides an overview of these efforts, describes the fields and details major subsurface uncertainties. Key aspects are:3D, object-based geological modelling of the reservoir, covering the spectrum of plausible sedimentological interpretations.Convolution of rock properties, derived from seismic (AVO) inversion, with 3D geological model realisations to define reservoir properties in inter-well areas.Incorporation of faults (both seismically mapped and probabilistically modelled sub-seismic faults) into both the static 3D reservoir models and the dynamic reservoir simulations.Interpretation of a tilted gas-water contact apparently arising from flow of water in the Plover aquifer away from active tectonism to the north.Extensive gas and condensate fluid analysis and modelling.Scenario-based approach to dynamic modelling.In summary, acquisition of an extensive suite of quality data during the past two-three years coupled with novel, integrated, state-of-the-art analysis of the subsurface has led to a major increase in estimates of potentially recoverable gas and condensate. Improved volumetric confidence in conjunction with both traditional and innovative engineering design (e.g. Floating Liquefied Natural Gas technology) has made viable a range of possible commercial developments from 2005 onwards.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Sunrise and Troubadour Fields form a massive offshore gas-condensate resource located in the Timor Sea, 450 kilometres northwest of Darwin. The commercialisation, marketing and contract negotiations for such a world scale gas development requires confidence in reservoir performance and product composition, plus a clear appreciation of their uncertainties. This paper discusses how the key dynamic uncertainties have been identified, evaluated and modelled to determine their impact on development decisions.Early cross section models identified connected gasinitially-in-place and reservoir quality as key uncertainties, impacting field performance. Simultaneously, preliminary marketing efforts and facility design recognised fluid properties as a key parameter. This directed data acquisition through appraisal wells, which were fully cored and production tested.Iso-kinetic sampling and careful well test design has resulted in representative compositional data and identified compositional variations across the field. High rate dependent skins measured in appraisal wells have been evaluated and requantified for development wells. Detailed single well models have evaluated the effects of condensate banking.As marketing efforts progressed, full field simulation became warranted to capture remaining uncertainty on reservoir quality and distribution, and fault transmissibility. A suite of full field dynamic models built around the key dynamic uncertainties has provided confidence that uncertainties are manageable and that the development and customer commitments are robust. The case for further data acquisition, aimed at optimising the final development, can readily be made using the suite of dynamic models which integrate the input from all sub-surface disciplines.Focused appraisal has reduced and quantified the key uncertainties. The leading edge evaluation methods have removed the need for several additional appraisal wells that might otherwise have been required.Effective communication and teamwork between subsurface, facility engineering, commercial and marketing has proved crucial to ensure that the appropriate uncertainties were addressed in a timely manner as each discipline matured their part of the project.

The need for an improved model of the Tirrawarra Oil Field reservoir led to a characterisation project jointly undertaken by SANTOS Ltd and the Bureau of Economic Geology. The objectives of the project were to describe and characterise the geological complexity of the field and within this framework to quantify the residency of the original and remaining oil resource.A detailed facies based flow-unit model was developed, within which petrophysical parameters and pay distribution have been mapped. Four principal facies were identified from which six flow units were characterised in detail. The environments of deposition were shown to control the detailed fabric of the rock, which in turn controls reservoir properties and productivity. The reservoir is interpreted to have been deposited as a braid delta, which has been reworked by a lacustrine shoreface transgressing and regressing across the area in response to rapid and frequent changes in lake level. Consequently, the two main flow units are relatively uniform in character, with much of the production-reducing shale being removed. The new reservoir model provides a greatly improved explanation of field performance, particularly that which was previously considered anomalous. This attests to the reliability of the model for use in reservoir engineering studies and the identification of opportunities for incremental development of the large oil resource remaining in the field.Under-developed portions of the field are now being assessed for miscible flood expansion with the aim of future growth in both oil production and reserves.

The Sunrise-Troubadour giant gas-condensate fields lie on a massive, broad, low-relief structure 75km long and 50km wide. The fields have a gross reservoir thickness of 80m. They are located on the north western boundary of the Australian Plate and form the basis of a proposed green-field LNG project and an Australian domestic gas development. Statistical volumetric analysis has shown that reservoir quality, distribution and Net-To-Gross ratio (NTG) are the main static uncertainties affecting Gas-Initially-In-Place (GIIP). These parameters are a function of the environment of deposition of the reservoir interval. The low average NTG in some wells (as low as 30%) indicates potential for depositional heterogeneity which can impact dynamic fluid flow through the reservoir. Depositional modelling has therefore been a major focus for field evaluation and appraisal. The reservoir interval was deposited in a marginal marine setting on a slowly subsiding, broad, low-relief shelf. The overall retrogradational character of the reservoir interval is illustrated by the upward increase in the open marine character of the interbedded shales. There are two major relative sea level falls interpreted which resulted in the deposition of incised-valley and sharp-based, forced regressive shoreface deposits. These sandbodies form the major reservoir units in the fields. Highstand and transgressive deposits are characterised by relatively thin and discontinuous sandbodies. In order to fully capture the depositional uncertainty inherent in a field of this scale which only has limited well control (six wells), three groups consisting of sedimentologists, stratigraphers and biostratigraphers have independently interpreted the core and wireline data. The result was three different depositional interpretations. From these interpretations a most likely depositional model was developed. Low and high case 3-D depositional models were generated by varying NTG and sandbody correlatibility and geometries. The adjustment of these parameters reflected the range of depositional interpretations from the three individual expert groups. These models form the basis of multi-scenario reservoir simulation studies which indicate that development options for these fields are technically robust for the range of perceived subsurface scenarios. Introduction The Sunrise-Troubadour gas-condensate fields are located 450 km northwest of Darwin on the edge of the Australian continental shelf and 50 km from the adjacent Timor Trench (Fig. 1). Together they hold in-place volumes ranging from (P90 to P10) 11.6 to 24 Tcf gas and 510 to 1055 million bbls condensate. The fields have a combined areal closure of 1000 square kilometres with a maximum vertical closure of only 180 metres. The main reservoir interval is the Bathonian Upper Plover Formation.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn this paper we present two methods for calculating uncertainty ranges for connected hydrocarbon volumes as applied to the Sunrise gas-condensate field, Timor Sea. 1) A "quick look" approach which uses a simplified, exploration scale fault data set. 2) A more detailed fault interpretation which is integrated with 3-D geological and dynamic reservoir modelling techniques.Despite the differences in sophistication, the two methodologies generate similar results in terms of absolute connected hydrocarbon volume ranges.In both studies the fractal relationships between the fault throws, lengths and frequency of occurrence were used to determine the minimum throw of faults fully interpreted on the seismic. This structural interpretation was then augmented by the probabilistic infill of sub-seismic faults with throws greater than the critical juxtaposition-sealing throw of 20 m. The resulting maps were then used to estimate a range of potentially connected gas volumes.The large number of across fault sand-sand juxtapositions within the areally extensive field suggests that as a most likely case the reservoir is 100% connected due to effective communication across faults or around fault tips. Sensitivities were analysed around this most likely case. As a worst case scenario all faults were assumed to be totally sealing due to the potential effects of shale gouge or cataclasis. The quick look study, which took no account of any sedimentological connectivity issues, predicted a worst case connectivity of 77% whilst the detailed 3-D dynamic simulator study predicted a connectivity of 72%.Although the areal distribution of connected hydrocarbons was different for the two approaches, the similarity of the final connected volume figures suggests that the quick look methodology provides a useful technique for the rapid estimation of connected hydrocarbon volume ranges in fields with limited data content and perceived simple sandbody architectures.