The development of thin oil rims in carbonate reservoirs requires good understanding of structural setting, reservoir architecture and transition zone saturations. Fields that have a tectonic and/or geochemical history after initial charge are likely to challenge standard assumptions of fluid distribution, contacts and saturation-depth relationships. This paper is a case study illustrating downflank field extension opportunities in an oil rim, related to post-charge tectonics affecting fluid distribution and contacts. The structure of this article encompasses four different aspects:begins by explaining the geological concepts that are being postulated for downflank hydrocarbon potential,proposes the alternative methodology of concept-driven analysis for log data interpretation,explains in detail the methodology applied to existing field data for reservoir architecture and fluid fill description,summarises the outcome of the appraisal well with respect to alternative concepts. The workflows that justified the placement of appraisal wells downflank followed the philosophy of concept-driven analysis where data is used to eliminate hypothesis rather than averaged into one a-priori assumption or average fitting equations. The placement of the pilot appraisal well (at a depth interval and location where previous models predicted water-fill) has been enabled by the identification of stratigraphic rock types, regional variability of fracture intensity and the prediction of tilted contacts. The results of an appraisal well drilled in 2017 confirm the alternative concepts proposed from concept-driven analysis of legacy log data:–Flank reservoir thickness improvement due to post-deposition crestal erosion of best facies.–Fracture density reduction towards the northern flank of the dome structure.–Tilted oil contacts deepening towards the flank and related to paleo-charge.–Relatively dry oil production from deeper depth intervals with low oil saturation due to transition zone water mobility. The drive mechanism and development options for the field should be investigated further.

In this study development options are evaluated for a low permeability carbonate field located in the North of the Sultanate of Oman which has been on production since 1969. The dominant recovery mechanism is bottom aquifer water injection with an estimated recovery factor of around 50% till date. This study is aimed at testing the simultaneous injection concept and other water based EOR strategies for the field to present a range of options for future development. During the work several concepts were also designed to understand the impact of major heterogeneities on proposed recovery mechanisms, and to understand the role of gravitational forces on remaining oil distribution. Major findings of this work include the development of a range of recovery options for the field with incremental recovery ranging from 2% to 20% (Recovery Factor), improved understanding of the impact of heterogeneities and the role played by gravitational forces. The application of "Experimental Design" of simulation runs ensured capturing of the range of uncertainties in heterogeneities and provided a distribution of outcomes. Economics was evaluated for surfactant polymer flood and simultaneous injection concept to facilitate decision making.

The Khuff formation in the Yibal field is currently undergoing one of the largest field development campaigns in PDO. While the main project driver is securing gas production (highly sour) at a stable plateau rate, maximizing oil rim recovery and production is the main objective of the presented study. This is challenging as all wells are pre-drilled as per FDP recommendation and any later development optimization is expected to be difficult and costly. Newly available static (seismic, well log, borehole images) and dynamic (well test) data were utilized in a decision driven modelling approach to update existing static and dynamic models to confirm the robustness of subsurface development decisions, oil production promises and EUR. Updated structural and property modeling results were utilized to optimize placement of 2/3 of the remaining wells in order to improve drainage. Reservoir rock typing and fracture interpretation, along with cased-hole surveillance data acquired in all wells, were used to optimize production intervals and to confirm the productivity of the different intervals (dolostone/ limestone/ fractures); which were then integrated to confirm the perforation strategy going forward. This study describes the first development of Khuff carbonates in Sultanate of Oman, with limited historical production data and no analogues in Sultanate of Oman. The study highlights the importance of continuous integration of new data in a decision driven modelling approach to ensure robustness of project decisions with timely project adjustments to prevent NPV erosion.

The development of reservoirs that are not in hydrostatic equilibrium or that have suffered deviations from primary drainage over geological time requires appropriate challenges to standard assumptions in order to optimize the field's full potential. Such circumstances are more frequent than usually acknowledged since the Earth is not static, structures get buried or change with tectonic activity and fluids re-arrange themselves to achieve a state of minimum potential energy. The focus of this paper is three fold: a) highlight geological processes that may affect fluid distribution and pressure regime in a reservoir; b) provide a template workflow and diagnostic tools for identification of alternative fluid-fill cycle and equilibrium state scenarios; c) illustrate through actual field examples the relevance of recognising tectonic imprint on fluid distribution, in particular for reservoirs with low permeability, oil wettability or low porosity. A companion paper1 published at the same time discusses methods to model saturation changes in some of such complex fields. In summary, the interpretation of variable contacts within a field can result in changes to development decisions (see fig 1): consequences are not limited to volumetric assessment but they can actually change the development, well count and well placement as well as impacting the design of the facilities. Based on risk and opportunity management optimization we advise against indiscriminate standard assumptions of primary drainage or hydrostatic equilibrium for all reservoirs in all basins.