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Thi.s .study uses a 3D petroleum system modelling approach to investigate the links between hydrocarbon generation and migration with observed gas chimneys and gas leakage features along the western margin of offshore South Africa. In addition we have investigated the impact and timing of mass failures and related .sediment mass movement on the petroleum system and hydrocarlx)n maturation history within the southern Orange Basin.Our 3D-modeI covers this passive margin's evolution from Early Cretaceous drift initiation to the e.stablishment of a present day continental margin, extending from the shelf to the deep marine domain. The model is based on interpreted 2D seismic profiles and borehole data including sedimentological and geochemical analyses as well as heat flow data. The model includes a proven .source rock of Aptian/Albian age, and a second assumed Cenomanian Turonian source. Several heat flow and uplift-erosion scenarios have been tested with the model to assess consi.stency with calibration data and present day surface heat flow values. After calibration against known well temperatures and vitrinite reflectance hydrocarbon generation and migration have been modelled to investigate the initiation, duration and spatial di.stribution of petroleum accumulation and leakage within and through(iut the sedimentary column.The main sedimentary depocentres of the Orange Basin develop>ed from east to west, with a siliciclastic basin infill and aggradation during the Cretaceous and westward progradation during the Late Cenozoic. A Late Cretaceous epi.sode of margin instability occurred in the north western part of the study area followed by a second phase of Late Cenozoic mass movement in the south-western part of the study area. At the location of the Cretaceous mass failure the increase in .sediment load profoundly affected the underlying source rocks seen in modelled maturation and petroleum generation potential. Albian .source rocks .started hydrocarbon transformation 100 to 85 Ma ago (phases I to III) in the centre of the basin and between 75 to 65 Ma ago (phase IV and VI) towards the distal part of the basin. The highest generation rates occurred at 75 Ma, followed by a rapid decrease until 15 Ma and a slight increase in generation potential until present day (phase V) caused by enhanced Cenozoic sediment load we.st of the Cretaceous shelf break. This recent increase accounts for the location of present day gas generation, though it dcx;s not substantially affect the overall regional maturation history.Today's gas leakage features that have been observed in the shelf area (<400 m water depth) ea,st of the slope failures are fed by an active hydrocarbon system. Compared to these gas leakage sites, the location of gas generation in the outer basin implies subsequent migration of the fluids towards the near-shore part of the basin. Our modelling constrains the migration pathways, SOUTH

Residual gas and oil saturations and relative permeabilities have been quantified in the Maui Field. Additional Special Core Analysis (SCAL) laboratory data was acquired using decane/brine and oil/brine centrifuge experiments. Such measurements are considered most representative of water influx into gas and oil reservoirs respectively. In the case of oil, ageing of the samples to restore wettability is shown to be essential. Relative permeability curves were obtained by history matching the raw experimental production data via numerical simulation. This process corrects for experimental artefacts and limitations, resulting in a significant reduction in residual hydrocarbon saturations compared to typical analytical interpretations. A correlation using a form originally proposed by Land has been used to relate the residual hydrocarbon saturations to the initial water saturations. In-situ field measurements of hydrocarbon saturations using pulsed neutron logs in water-flooded zones are shown to support the SCAL data. The work described represents the state-of-the-art in quantification of residual hydrocarbons. In particular, the combination of the sampling methodology, the experiment design, the advanced numerical interpretation and the in-situ measurements is material previously unpublished in technical literature. The results are significant in that they show lower residual saturations than commonly expected, while adding to the limited published data on residual hydrocarbons. Use of lower residual hydrocarbon saturations together with the appropriate relative permeabilities in reservoir simulation has resulted in improved reservoir history matches and has had a positive influence on Maui Field reserves. Application of these state-of-the-art techniques to other water-drive fields is likely to have a similar impact. Introduction An understanding of the relative permeability of hydrocarbons and water is essential for reservoir simulation. The remaining hydrocarbon saturation after water flood and hence the ultimate recovery (UR) is strongly determined by the tail end shape of the imbibition relative permeability curve, close to the residual hydrocarbon saturation. This paper reports the results of extensive SCAL studies to better quantify relative permeabilities, including residual hydrocarbon saturations, in most of the gas and oil reservoirs of the Maui Field. The Maui gas and oil field, off the Taranaki coast, New Zealand, was discovered in 1969. Figure 1 gives an overview of the various gas/condensate and oil sands in the Maui-A and -B area. The Maui-A C and D gas sands were brought on stream in 1979 via a single production platform, MPA. In 1992 a second production platform, MPB, was installed to produce gas/condensate from the B area. In 1993 the Maui-B C and Upper D gas sands were brought on stream via this second platform tied back to the MPA platform. Also in 1993 an oil accumulation was discovered in the B F sands underlying the C and Upper D gas reservoirs and the Lower D oil reservoirs. The Maui-B Lower D and F oil sands have been producing since September 1996 via the FPSO Whakaaropai connected to MPB. The residual gas and oil saturations previously used for Maui reservoir modelling are high compared with recent state-of-the-art SCAL studies carried out on sandstone reservoirs from various fields around the world1. In these recent studies, a systematic reduction in residual hydrocarbon saturations, in combination with higher Corey exponents, is observed. There are two reasons that could explain the likely too-high estimates for the previous residual hydrocarbon saturation data.

The Eromanga Basin is an established Australian producing region with oil and gas found in several different Formations. At the request of an Operator, a project was undertaken to construct saturation-height functions for all the Eromanga reservoir units with a secondary objective being to define residual hydrocarbon saturations. Initial investigations revealed many reservoirs with residual hydrocarbon columns, the significance of which had not been well understood. The residual hydrocarbons implied that imbibition, rather than drainage, capillary pressure curves were representative of water saturations in the reservoir. This insight suggested higher oil-in-place and reserves volumes than previously assumed since mobile hydrocarbons are present very close to the pressure derived Free-Water Level in imbibition systems. When individual hydrocarbon Fields were considered, there were insufficient special core analyses to derive meaningful residual hydrocarbon or saturation-height relationships. However, on the basin scale, a significant volume of measurements had been acquired over a period of 22 years, albeit using different laboratories and a variety of measurement techniques. With knowledge of the measurement techniques and Formations sampled, the data were combined in such a way that consistent datasets were obtained for end-point relative permeabilities and drainage and imbibition capillary pressure curves. Interpretation of these datasets produced residual oil saturation and drainage and imbibition saturation height relationships. These relations were tested against those log-derived water saturations considered most reliable by the Operator, showing excellent matches. The model developed successfully described the water saturation distributions in the reservoirs tested in a manner not previously possible. Indeed, the use of the drainage and imbibition saturation-height functions together with residual hydrocarbon relationships provides a powerful tool to determine both static and dynamic fluid contacts, while checking the validity of wireline log-based water saturations. Introduction At the request of an Operator, a review has been undertaken of all the available Special Core Analyses (SCAL) for the Jurassic Oil reservoirs found in the Eromanga Basin of Australia. The primary objective of this study was to construct appropriate saturation-height functions for oil volume quantification and reservoir modelling. A secondary objective was the identification of residual oil saturations from suitable core analyses. The Jurassic reservoir units involved were the Adori, Basal-Jurassic, Birkhead, Hutton, McKinlay, Murta, Namur and Westbourne Formations. History The Eromanga Basin is an established producing area, with many fields and a large database of wireline log measurements and core analyses collected over more than 20 years. Despite a number of different Operators and a history of production in the area, the significance of the residual oil found below the pressure derived free-water levels (FWL) of many fields had not been fully recognised. The signs that imbibition may be significant in reservoirs include:presence of "residual oil" below the pressure derived FWL at discovery,dry oil production from close to a FWL,sharper log-derived transition zones than the reservoir permeability suggests. In addition, as oil fields are produced, water sweeps through sections of reservoir. These sections have gone or are undergoing water imbibition.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractResidual gas and oil saturations and relative permeabilities have been quantified in the Maui Field. Additional Special Core Analysis (SCAL) laboratory data was acquired using decane/brine and oil/brine centrifuge experiments. Such measurements are considered most representative of water influx into gas and oil reservoirs respectively. In the case of oil, ageing of the samples to restore wettability is shown to be essential. Relative permeability curves were obtained by history matching the raw experimental production data via numerical simulation. This process corrects for experimental artefacts and limitations, resulting in a significant reduction in residual hydrocarbon saturations compared to typical analytical interpretations. A correlation using a form originally proposed by Land has been used to relate the residual hydrocarbon saturations to the initial water saturations. In-situ field measurements of hydrocarbon saturations using pulsed neutron logs in water-flooded zones are shown to support the SCAL data.The work described represents the state-of-the-art in quantification of residual hydrocarbons. In particular, the combination of the sampling methodology, the experiment design, the advanced numerical interpretation and the in-situ measurements is material previously unpublished in technical literature. The results are significant in that they show lower residual saturations than commonly expected, while adding to the limited published data on residual hydrocarbons. Use of lower residual hydrocarbon saturations together with the appropriate relative permeabilities in reservoir simulation has resulted in improved reservoir history matches and has had a positive influence on Maui Field reserves. Application of these state-of-the-art techniques to other water-drive fields is likely to have a similar impact. S w k rw Steady-State #01