The present day tectonic configuration of the Timor Sea area is the product of multiple phases of deformation occurring from the Proterozoic to the Holocene. Each major phase of deformation has produced structural hydrocarbon traps, which, in many cases, have subsequently undergone considerable reactivation, and in some cases, breaching. The last phase of tectonism affecting the region is the Neogene collision of the Australian and SE Asian Plates in the Banda Arc region. Although its importance in trap modification and integrity has been acknowledged, a cohesive tectonic model integrating observations that cross the international border has been lacking. The observed Neogene structural deformation and subsidence/uplift trends of the Australian shelf in the Greater Timor Sea can be explained by a combination of strike-slip faulting and flexure as the result of oblique convergence and partial subduction of the Indo-Australian Plate under the Southeast Asian plate. Neogene subsidence and deformation of the Cartier Trough and Malita Graben are interpreted to be the result of rhomb graben (i.e. pull-apart) basin development associated with sinistral shear and reactivation of relict rift structures. These basins developed along 'releasing bends' on the west-northwestward dipping flanks of rigid basement highs. Conversely, in areas where existing basement structure trends define 'confining bends' (e.g. southeast-eastward dipping flanks of basement high features), older rift structures have been reactivated transpressionally, in some cases resulting in large-scale inversion. The present day bathymetry suggests that these rhomb-grabens are currently active. In addition to the wrench-related deformation associated with oblique plate convergence and partial subduction, the Australian shelf has undergone flexure resulting in extension. It is proposed that the Neogene palaeo-and the present day stress fields of the Australian shelf reflect the combination of shear stresses related to wrenching and the tensional stresses related to flexure as the Australian Plate is obliquely subducted. Understanding of this modus operandi has direct bearing to hydrocarbon exploration as areas of structural risk (i.e. structures prone to trap breaching) can be delineated. In general trap breaching risk is lower in areas lying away from the shelf margin and away from 'releasing bends' along shear zones.

The Central North Sea contains a large variety of oil and gas fields at different stages of maturity within the life cycle of an asset, at varying depths, in varied geology and at widely differing pressure and temperature conditions. Over the last three years Shell UK Exploration and Production (Shell Expro) has acquired new 3D surveys over many of these fields which, following careful attention to detail in acquisition and processing, have been quantitatively compared to pre-production surveys. Differences between these time-lapse seismic datasets have then been interpreted in terms of changes in reservoir fluid movement and changed pressure/temperature conditions. These interpretations have proven useful for reservoir management by identifying swept versus unswept zones, sealing versus non-sealing faults, efficiency of drive mechanisms and connected volumes to specific wells Four case studies from the Gannet Development illustrate how these observations have impacted reservoir management and show how application of this relatively new, yet rapidly maturing technology has had a positive impact on the remaining value of these fields. Importantly, the detectability of changes in the reservoir has been seen to be greater than predicted prior to data acquisition. Indeed, 4D seismic data have become an established part of the long-term plans for all of Shell Expro's subsurface assets. With these successes have come fresh challenges and future efforts will focus on reducing costs in proven 4D technology whilst pushing to introduce new techniques for data gathering and for interpretation of large volumes of new information.

A case study is presented from an oil field in the Sultanate of Oman, operated by Petroleum Development Oman. To date the field has seen limited production under natural depletion (~1% of STOIIP produced). Most of the oil is located in 20–25 m thick oil rims with large gas caps in the reservoirs of the Gharif and Al Khlata formations. A Field Study was kicked off in PDO in 2004, triggered by the results of recent appraisal wells and has substantiated significant additional field potential. This paper extends previous work [Ref 1] in which we set out the use of Experimental Design for subsurface uncertainties analysis and development options evaluation for an oil field in the Sultanate of Oman. Here, we demonstrate for the first time how the multi-scenario ED modeling results can be taken one step further in Field Development optimisation. We introduce the concept of "Well Maturity Index" which quantifies the impact of subsurface uncertainties on EUR for each well in the selected development. The Well Maturity Index was used to guide decisions on the phasing of development and appraisal drilling and to help formulate a data acquisition programme for the field. This approach has resulted in an auditable and quantified decision-based plan for maximizing NPV and minimising risk, and adds significant value to the development planning process. This work also provides a natural stepping stone for a quantifiable Value of Information analysis, and scenario planning based on appraisal outcomes. The methodology used is general and should find application in many field development studies.. Introduction The Case Study field is located in onshore North Oman and is operated by Petroleum Development Oman. The relatively light oil is located in stacked oil rims beneath large gas caps in four different reservoirs (AK, LG, MG and UG). The field is associated with a mainly dip-closed, low relief faulted anticline, with its crest at a depth of 3000 m. Intervening shales and tight limestones act as intra-reservoir seals, and the UG, MG and LG/AK formations have separate fluid contacts. To date the field has seen limited production under natural depletion with three phase flow to remote processing facilities. A schematic of the field is given in Figure 1. A Field Development Plan (FDP) was derived after an extensive multi-scenario modeling approach using Experimental Design [Ref 1], followed by deterministic optimisation and by testing of the development against subsurface uncertainty. Key elements of the FDP are:Initial drilling to fill existing and committed facilities with low GOR oil by developing the AK oil rim with horizontal wells, coupled with appraisal of the overlying LG MG and UG reservoirs.Installation of full field facilities. Gas separation and compression with gas and oil/water routed to dedicated processing facilities. The increased capacity to be filled with production from potentially higher GOR LG and UG reservoirs.Final gas cap blow down will be carried out at the end of economic oil production. The multi-scenario ED results have also created a wealth of useful data, that can be further explored. A more detailed quantification of the impact of subsurface uncertainties can be pursued for the final development, on a well by well basis. This paper describes how this has further refined the phasing of development and appraisal drilling and how this has tailored the data acquisition programme to be more specific to each of the wells. Also, ranges for key surface facility design parameters were defined and were used for further optimisation the design specifications. Experimental Design Results Experimental Design is a mathematical technique which aims at representative sampling of the full parameter space with a relatively small number of parameter combinations. It is now widely recognized in the oil industry that ED provides a robust and time efficient way of handling multi-factorial problems such as volumetric calculations, history matching and development screening [Ref 1- 8].

fax 01-972-952-9435. AbstractExperimental Design has been used to screen a wide range of potential development options available for an oil rim reservoir, to examine the effect on the development of dependencies between surface and subsurface parameters, and to test the robustness of the optimised project against subsurface uncertainty. The ED algorithm used in this study enabled parameter screening and the parameter interactions to be performed in one step. Development screening was carried out by a process of eliminating options which impacted negatively on recovery and NPV. The interaction between surface and subsurface parameters was assessed and confirmed the robustness of the selected development. Final optimisation of the chosen development was carried out deterministically. Screening of the optimised development against subsurface uncertainty was used to derive a range of production forecasts, to guide the phasing of the development, and to formulate data gathering and appraisal plans.

Exploration within the Kopervik play is impeded by difficulty in imaging the Kopervik Sandstone on seismic data due to the lack of acoustic impedance contrast between the sandstones and overlying shales. The exploration method employed in the mapping of the Kopervik play fairway of the South Halibut Basin on poorquality 3D seismic data, leading to the Goldeneye Field discovery, is described. In the early 1990s, Shell/Esso acquired acreage in the South Halibut Basin based on the identification on 2D seismic data of a number of potential stratigraphic traps in the Kopervik play. The first well targeted an Apto-Albian isochron thick, just south of the proven Kopervik fairway, but encountered no reservoir. Subsequent mapping better delineated the fairway as being restricted to the southern fringe of the South Halibut Shelf. The basal sequence boundary was mapped locally on 3D seismic data and amplitude extractions were interpreted as showing erosion at the base of the Kopervik channel complex. At the northern edge of this fairway, a small four-way dip closure identified above Goldeneye on a regionally mappable seismic reflector did not conform to deeper structure, suggesting the presence of a thick section of mounded Kopervik Sandstone. The presence of gas/condensate in thin Jurassic sandstones in a well immediately north of this closure, far removed from the Jurassic gas kitchen, suggested that long-distance migration had occurred along the Kopervik fairway and hence that gas might be trapped at Goldeneye. The Goldeneye discovery well, drilled in 1996, encountered a 305 ft column of gas/condensate above a thin oil rim within the thickest section of Lower Cretaceous Kopervik Sandstone so far encountered in the Outer Moray Firth. Subsequently, two further prospects were drilled with mixed results. The Goldeneye structure is now considered unique within the Ettrick sub-basin of the South Halibut Basin.