South Sumatra Basin is an inverted post-arc Tertiary basin, which has a complex evolution history from late Eocene-Oligocene extension to late Miocene and Pliocene compression. To evaluate the overall basin prospectivity, a regional analysis is conducted at 8 stratigraphic levels from pre-Tertiary unconformity to Pleistocene. An integrated interpretation including more than 1400 2D seismic lines, 4 seismic 3D surveys, and formation evaluation from 80 key wells is used to run the basin analysis. A series of regional seismic transects are defined through key wells and major structural elements to capture the characteristics of structural styles, lithostratigraphy and hydrocarbon distribution across the basin.Structural restorations unravels the timing of fault activity showing basin rifting until ~23 Ma with main depocenters in Benakat Gully, Limau Graben, Central Palembang and Lematang Depression followed by sagging until 14.6 Ma. The compressive event is recorded from 5 Ma to present day. The buckling of syn-rift sediments suggests shortening expressed by inversion and fault reactivation rather than thrusting. Review of the source rock data, reservoir distribution, hydrocarbon phase and source to reservoir correlation data are evaluated in perspective of the basin configuration in order to select sections for basin modeling. The modeling results show onset of expulsion varying from ~10-15 Ma from Lemat Fm. and Talangakar Fm., and 5 Ma from Telisa Fm. Modeling suggests that Talangakar Fm. reservoirs are completely filled, whereas Lemat Fm. reservoirs are partially filled due to limited lateral and downward migration. Baturaja Fm. reservoirs in proximity to depressions are filled, and partial charge risk away from kitchen area. Most of the hydrocarbon are generated, expelled and accumulated between sedimentation of Lower Palembang Fm. to inversion time (10-5 Ma). The subsequent inversion is likely to have re-migrated hydrocarbon in Talangakar and Baturaja reservoirs along Benakat Gulley and associated fault bound folds.
Understanding of water breakthrough risks in complex multi-layer fractured reservoir is a critical aspect in developing and maximizing recovery of gas condensate assets. An integrated study involving multiple model realizations (single porosity, dual porosity-single permeability and dual porosity-dual permeability) was conducted in order to understand various water production risk scenarios. Study resulted in an opportunity for an effective production optimization after 10 years of production history from a gas condensate field in South-East of Algeria. In some modeling processes, the model is often built with one realization. Hence, dynamic data calibration and prediction lead to a stringent concept. Consequently, water risks are not fully assessed due to limited perspective. In this study, the dynamic modelling was enhanced with history matching regressions on multiple static model realizations resulting in a range of production forecasts. This significantly helped in understanding water production challenges in terms of breakthrough timing, water conduits and direction that was initially not obvious with a single realization concept. As a result, a better mitigation plan was devised to address those challenges. A new approach in modeling natural fracture reservoirs was applied during the static modelling process that resulted in proper fracture distribution in 3D and enabled a static model adaptive to surveillance data hence mitigating some core data gap. The process included quantitative model property adjustment based on an integrated multidomain approach including results of a detailed pressure transient analysis across different areas of the field, borehole image interpretation, characterization of conductive fractures, incorporation of production logging data and other surveillance data sets. A robust compositional model that allows accurate computation liquified petroleum gas and condensates recovery was implemented to improve the surveillance program and highlighting infrastructure debottlenecking requirements. This paper presents the results from a detailed analysis of multiple water risks scenarios from a complex multi-layer fractured gas condensate reservoir and discusses its impact on optimizing the field development plan. A systematic ranking was established to compare various water mitigation solutions and production optimization opportunity based on potential gain, operational complexity, and economical due diligence. The study helped the operator and field management team to select optiaml field development plan in addition to achieving hydrocarbon production sustainability assurance resulting in a substantial incremental gas recovery. The workflow presented in this study can be readily adopted for other gas condensate fields towards improved modeling practices in order to lay out some critical foundations prior to embarking into larger studies such as a fully integrated subsurface and surface network modelling to generate a robust production enhancement action plan.
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