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The Late Neogene Baram Delta province developed on an active margin located offshore Borneo in Malaysia. The field has been in production since 1982, and a total of 64 wells have been drilled from three (3) platforms. This paper discusses the process used to locate remaining oil for infill drilling. This involved a multidisciplinary effort including geology and geophysics, reservoir engineering, drilling / completion, and production technology. The geologic and geophysical (G&G) assessment consisted of updating the static model and constructing mobile oil thickness and structural and bubble maps of all reservoirs. These maps were used in conjunction with original and current fluid contacts and helped to identify and locate remaining oil accumulations. The target portfolio was screened and ranked, and preliminary wellbore paths were built. Four (4) new wells and eight (8) sidetracks combining either shallow or deep targets were passed on to the reservoir engineering team for optimisation from simulation models and first-pass estimation of oil incremental reserves. Reservoir simulation focuses on optimising target intervals as determined through G&G work and drilling design. Well constraints are set to be consistent with operating field production practices and facilities constraints. Completion intervals for the dual-string wells are optimized to minimise water cut and maximise oil rates. All simulation results are rigorously checked against offset well production and observed properties. Once drilling targets are risk-assessed on the basis of structural, fluid contacts, and properties uncertainties, the final well trajectories are designed by the drilling team. This study identified and ranked multiple undrained and appraisal areas. A full infill redevelopment consisting of more than 10 accelerated wells planned through the utilisation of existing facilities was presented and approved by PETRONAS Carigali Sdn. Bhd. (PCSB). The well and target portfolio is focused on three (3) main field development areas: Attic oil in shallow Pliocene reservoirsNew development areas in deeper Miocene levels on the southern blockUntapped deep Miocene reservoirs on the northeastern flank in crestal location The first two (2) sidetracks and three (3) workovers were successfully completed in December 2012, and the current oil production is 40% higher than originally estimated. The successes to date have proved the effectiveness of the concepts that were applied to identify and develop the remaining oil, and the field became East Malaysia's top producer.

TX 75083-3836, U.S.A., fax +1-972-952-9435. AbstractA unique integrated borehole seismic technique was used to access and mitigate drilling risk on a Petronas Carigali highpressure, high-temperature (HPHT) exploration well offshore Sabah.The approach combined wireline vertical seismic profiling (VSP) and logging-while-drilling (LWD) seismic surveys to look ahead for pore-pressure prediction, geostopping, and obtaining high-resolution seismic imaging below the well path. Three wireline VSP runs and one seismic-while-drilling run were made. The first-run rig-source VSP at the 13 3/8-in. section was used to obtain an initial velocity model and early prediction ahead of bit and imaging. This was followed by a wireline vertical incident VSP (VIVSP) run at the 9 5/8-in. section to refine the pore pressure prediction and for target illumination. LWD seismic was deployed while drilling the following 8 3/8-in. section to provide real-time checkshots for pore-pressure constraint and geostopping above a key formation top to set casing. Both the wireline and LWD VIVSP showed minor faults that were not apparent on the 3D surface seismic; these faults explain the unusual kick encountered. This high-resolution image was used to decide the sidetrack path. The final rig-source VSP was logged at total depth (TD) to complement the pore-pressure prediction and seismic imaging.In addition, the real-time checkshots while drilling aided in stopping drilling to within a stand (less than 30 m) above the key formation top. The depth uncertainty of the key formation was over 130 m prior to drilling.

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