Samarang Field - Redevelopment Evaluation Brings New Life to an Old Oil Field
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 13162, ’Samarang Field - Seismic-to-Simulation Redevelopment Evaluation Brings New Life to an Old Oil Field, Offshore Sabah, Malaysia,’ by J.K. Forrest, SPE, Schlumberger; A. Hussain, SPE, and M. Orozco, SPE, Petronas Carigali Shd. Bhd.; and J.P. Bourge, SPE, T. Bui, SPE, R. Henson, SPE, and J. Jalaludin, SPE, Schlumberger, originally prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December. The paper has not been peer reviewed.

The Samarang field is offshore Sabah, East Malaysia, approximately 45 miles northwest of the Labuan gas terminal. The field surrounds a shallow reef with a water depth of 30 ft. Shell was the initial operator and relinquished the concession to Petronas Carigali Sdn. Bhd. (PCSB) in April 1995. 

Field-Development History

Fig. 1 summarizes the production and development history of the field. The field was developed in phases, with the initial phase including the larger A and B drilling platforms; separate producing platforms at A, B, and C; and well jackets at C, D, and E. Subsequent development included well jackets at F and G. An additional well jacket, H, was planned by Shell for the east-flank development but was not implemented in 1986 because of low reserves potential and low oil prices.

Formation Evaluation and Characterization

A 1984 3D-seismic survey is available and was interpreted, but the best data and control are provided by the openhole logs from 144 wells. Within the field, log correlation is good in general. All of the producing reservoirs in the field are normally pressured, and the field has a normal temperature gradient for the area of approximately 1.05°/100 ft.

The cored interval comprises three main facies types (i.e., sandstones, heterolithic sandstones, and shales). These facies types then were subclassified into nine lithofacies to cover the broad spectrum of sand/shale content, primary sedimentary structures, intensity of bioturbation, and unique sedimentologic character that was identified and described from the core. The ninth lithofacies in the cored intervals represents the presence of carbonates in the form of patchy carbonate cement, broken/intact shell hash layers, dolomite patches, and layered or nodular siderites. This last lithofacies, though negligible in occurrence in the whole cored section (0.4% of the total cored interval), was important as a local vertical-flow baffle.

Following the identification of these lithofacies, geologists used a neural-network procedure to extend the lithofacies to most of the noncored wells. Some of the wells had wellbore problems including missing logs or cork-screwed boreholes, which did not allow their inclusion in this work. But in all cases, there was sufficient well coverage to allow the estimation of lithofacies throughout the reservoir sequences. The final neural-network model involved used the sand, silt, and clay volumes for each individual well as calculated by petrophysical methods.