>Magister Scientiae - MSc / The Sable Field constitutes a Basin Floor Channel (BFC) complex (E-BD reservoir) and a Basin Floor Fan (BFF) complex (E-CE reservoir). The reservoir sands were deposited during early-drift sedimentation in the Bredasdorp Basin. Paleo-current flows from the west, filling the basin with sediments that are eroded off the continental shelf (Agulhus Arch) and deposited on the base of the continental slope and basin floor. Turbidite flows off the Agulhus arch have deposited the Sable Fields reservoirs, where the larger channelized reservoir body takes an 80° bend off the continental slope and flows onto the basin floor. This 3-D reservoir highlights the reservoirs internal heterogeneity and complexity at the well bore and away from the well bore. Well tops tie wells to the 3-D seismic cube for; reservoir location and delineation, velocity modelling and subsequent conversion of the mapped surfaces from time to depth. Core and petro-physical analysis were used to outline the depositional facies within the investigated wells namely: E-BD5, E-BD2, E-BD1 and E-CE1. Correlation of depositional facies at the well bore with their corresponding seismic facies, allows for extrapolation of facies away from the well bore. The internal heterogeneity of the reservoir is outlined using an integrated methodology, which is based on log scale depositional features (channels, sheets, lobes) that are extrapolated to field scale (sand rich complex) using corresponding top and base reservoir seismic responses. The investigated thick region of sediment accumulation on: the continental slope, the base of the continental slope and basin floor is deposited on the 13AT1 early drift unconformity. The reservoir is outlined from the up-dip to the down-dip reaches of the field. Well E–BD5 has tapped into the proximal region (up-dip), with reservoir comprising of amalgamated channel sands that are deposited by laterally switching and stacking channelized sand bodies. Channel meander facies are seen in the upper portion of the reservoir, with massive channel fill in the lower parts. The channel fill constitutes a high net to gross with little to no lateral facies variations. This confined environment is dominated by amalgamated massive sands (on-axis) that are thinner bedded towards the banks of the channels (off-axis). A high degree of channel amalgamation has been interpreted in both up-dip wells E-BD5 and E-BD2. This channelized reservoir is at least 2km wide and 6km long, before the larger channel makes a rapid 80° change in paleo-current direction. This is possibly the result of basin floor topography and the stacking of previously deposited sand complexes which alter local sea floor topography. The vertical and lateral continuity of the channelised reservoir is generally excellent due to the high degree of channel amalgamation. The stacked channel complex constitutes a gross thickness of 76.2m (68.5m Net sand) in well E-BD5, and a gross thickness 25m (23m Net sand) in well E-BD2. Channel sands in well E-BD5 have an average porosity of 15% while the average porosity of channel sands in well E-BD2 (further down-dip) is 17%. This up-dip channelised region results in high amplitude reflections due to hydrocarbon charged sand juxtaposed against hemipelagic muds and silty levee facies. Well E-BD1 has tapped into a relatively confined sand complex deposited at the base of the continental slope. The amalgamated lobe and sheet sand complex is entirely encased in hemi pelagic mud. These reservoir sands are interpreted to be deposited in the Channel Lobe Transition Zone (CLTZ), thus the reservoir sands are interpreted to have a transitional depositional style (generally channelized sheets). The CLTZ region is thus dominated by both channel complex and lobe complex elements. The E-BD1 reservoir constitutes a number of amalgamated elements that result in a reservoir zone with an average porosity of 16.4%. These include: amalgamated thick bedded sheet sand (lobe axis) associated with deep depositional feeder channels; thin bedded sheet sands (off lobe axis), broad thin amalgamated lobe elements, layered thick bedded sand sheets and deep broad depositional channels. The low sinuosity broad depositional-channels and elongate lobe elements are expressed as lobate amalgamated sheets of sand which is up to 2-3km wide, 5km long and 30m thick (29.7m nett sand) at the well bore. Well E-CE1 has intersected 50m thick reservoir sand (50m nett sand) which constitutes the axis of a lobe complex where the reservoir zone has an average porosity of 14%. The sand rich complex is deposited on the unconfined basin floor. This reservoir complex constitutes amalgamated thick bedded lobe architectural elements which are massive in nature. The laterally continuous hydrocarbon charged lobe elements result in bright parallel seismic reflections. The amalgamated lobe complex is more than 5km wide. Sub-parallel horizons are attributed to the thin bedded off axis portion of the lobe complex where the net to gross is considerably less than the highly amalgamated axis of the lobe complex. The lobe complex has a moderate to good net to gross of 40-60%. The high aspect ratio of the lobe complex severely impacts the reservoirs vertical permeability, however horizontal permeability is quite good due to the extensive lateral continuity of good quality sheet sands. Based on the nature deep water architectural elements observed in this study, the internal heterogeneity of the Basin floor Fan and Basin floor channel complex’s may constitute an entire sand rich reservoir zone. All the sands may be in hydraulic communication if they are genetically related. These sands and stretch from the up-dip (wells E-BD5 & E-BD2) through to the transitional (E-BD2) and pinching out in the distal regions (E-CE1) on the basin floor. The seal constitutes a prominent shale horizon T13PW3 (8-10m thick) which is draped over the entire reservoir complex. This top seal is extrapolated from all the wells and correlated with seismic facies, thus outlining the lateral continuity and thickness variations of the top seal. This draped shale horizon exposes the thick axial portion of the amalgamated channel complex and amalgamated lobe complex.

Despite increasing computer power, the requirement to upscale 3D geological models for dynamic reservoir simulation purposes is likely to remain in many commercial environments. This study established that there is a relationship between sandbody size, cell size and changes to predictions of reservoir production as grids are upscaled. The concept of a cell width to sandbody width ratio (CSWR) was developed to allow the comparison of changes in reservoir performance as grids are upscaled. A case study of the Flounder Field in the Gippsland Basin resulted in the interpretation of three depositional environments in the intra-Latrobe reservoir interval. The sandbody dimensions associated with these depositional environments were used to build a series of 3D geological models. These were upscaled vertically and horizontally to numerous grid cell sizes. Results from over 1400 dynamic models indicate that if the CSWR is kept below 0.3 there will be a strong correlation between the average production from the upscaled grids compared to those of a much finer grid, and there will be less than 10% variation in average total field production. If the CSWR is between 0.3 and 1, there could be up to 30% difference, and once the CSWR exceeds 1.0 there is only a weak relationship between the results from upscaled grids and those of finer grids. As grids are upscaled the morphology of bodies in facies models changes, the distribution of petrophysical properties is attenuated and the structure is smoothed. All these factors result in a simplification of the fluid flow pathways through a model. Significant loss of morphology occurs when cells are upscaled to more than a half the width of the reservoir body being modelled. A simple rule of thumb is established — if the geological features of a model cannot be recognised when looking at a layer in the upscaled grid, the properties of the upscaled grid are unlikely to be similar to those of the original grid and the predictions of dynamic models may vary significantly from those of a finer grid. This understanding of the influence of sandbody size on the behaviour of upscaled dynamic models can be used in the planning stages of a reservoir modelling project. Two simple charts have been created. The first chart is for calculating the approximate number of cells in a model before it is built. The second chart is for comparing the proposed cell size against the CWSR, so that the predicted discrepancy between the ultimate production from the upscaled grid and one with much smaller cells can be assessed. These two charts enhance discussion between all interested disciplines regarding the potential dimensions of both static and upscaled dynamic models during the planning stage of a modelling project, and how that may influence the results of dynamic modelling. / http://proxy.library.adelaide.edu.au/login?url= http://library.adelaide.edu.au/cgi-bin/Pwebrecon.cgi?BBID=1375309 / Thesis (Ph.D.) - University of Adelaide, Australian School of Petroleum, 2009

Despite increasing computer power, the requirement to upscale 3D geological models for dynamic reservoir simulation purposes is likely to remain in many commercial environments. This study established that there is a relationship between sandbody size, cell size and changes to predictions of reservoir production as grids are upscaled. The concept of a cell width to sandbody width ratio (CSWR) was developed to allow the comparison of changes in reservoir performance as grids are upscaled. A case study of the Flounder Field in the Gippsland Basin resulted in the interpretation of three depositional environments in the intra-Latrobe reservoir interval. The sandbody dimensions associated with these depositional environments were used to build a series of 3D geological models. These were upscaled vertically and horizontally to numerous grid cell sizes. Results from over 1400 dynamic models indicate that if the CSWR is kept below 0.3 there will be a strong correlation between the average production from the upscaled grids compared to those of a much finer grid, and there will be less than 10% variation in average total field production. If the CSWR is between 0.3 and 1, there could be up to 30% difference, and once the CSWR exceeds 1.0 there is only a weak relationship between the results from upscaled grids and those of finer grids. As grids are upscaled the morphology of bodies in facies models changes, the distribution of petrophysical properties is attenuated and the structure is smoothed. All these factors result in a simplification of the fluid flow pathways through a model. Significant loss of morphology occurs when cells are upscaled to more than a half the width of the reservoir body being modelled. A simple rule of thumb is established — if the geological features of a model cannot be recognised when looking at a layer in the upscaled grid, the properties of the upscaled grid are unlikely to be similar to those of the original grid and the predictions of dynamic models may vary significantly from those of a finer grid. This understanding of the influence of sandbody size on the behaviour of upscaled dynamic models can be used in the planning stages of a reservoir modelling project. Two simple charts have been created. The first chart is for calculating the approximate number of cells in a model before it is built. The second chart is for comparing the proposed cell size against the CWSR, so that the predicted discrepancy between the ultimate production from the upscaled grid and one with much smaller cells can be assessed. These two charts enhance discussion between all interested disciplines regarding the potential dimensions of both static and upscaled dynamic models during the planning stage of a modelling project, and how that may influence the results of dynamic modelling. / http://proxy.library.adelaide.edu.au/login?url= http://library.adelaide.edu.au/cgi-bin/Pwebrecon.cgi?BBID=1375309 / Thesis (Ph.D.) - University of Adelaide, Australian School of Petroleum, 2009