Kujung formation in East Java basin is carbonate reservoir and deposited in late Oligocene to early Miocene. It is divided into 3 reservoir targets and potentially has different flow units, which believe predominantly due to secondary porosity. The exploration wells drilled on Kujung-I reservoir was known dominantly produced of gas while the other 2 reservoirs unit in Kujung has commingled oil and water production. Identification of the fluid type on those reservoirs unit found difficult if using Archie-resistivity based saturation. Fresh water environment creates low contrast resistivity between water and hydrocarbon and potential of mud losses complicated the interpretation.
The appraisal well on Kujung reservoir was planned on development well with significant high deviation. It has risk of well bore stability due to penetrating of complex stress regime. The lamination sequence of carbonate and shale created different stress contrast. Minimizing the time hole opened was mandatory to prevent of hole collapse and stuck. It implies to the logging strategy especially for any logging program which need long stationary time such as sampling and so the logging after drilling must be avoided.
Those challenge on fluid identification and operation risk made the operator to approach a different strategy for the logging requirement and interpretation used on determination of the fluid type in Kujung formation. Wireline logging program is not the first option and Logging While Drilling become primary data acquisition.
The first well-A used Nuclear Magnetic Resonance logging while drilling with primary out-put of the T2 distribution. Information of the T2 distribution can differentiate between free fluid and irreducible fluid inside the pore. This paper will discuss a novel statistical technique "factor analysis" employed to T2 distribution from NMR logging to differentiate finger print fluid type inside effective porosity in vuggy carbonate environment. This technique automatically searching for dominant T2 modes on each depth and extracts the most significant factors in terms of pore size and fluid type features present in the T2 distributions. This technique is different with conventional technique known "binning-porosity" fixed cut-off applied on the T2 distribution. The result of this technique was proved through the well test performed.
The subsequent well-B and well-C used different approach to identify fluid type in Kujung formation. It used formation pressure while drilling and the fluid identification will be inferred from the formation pressure gradient. The result does not give overall conclusive result for fluid identification due to the low mobility formation. Low mobility environment made the formation pressure acquired will be affected by the hydrostatic pressure. This approach was selected by considering of the necessary to acquire formation pressure cost effective strategy consideration.
This paper will discuss case study of the successful technique factor analysis on identification fluid type from T2 distribution NMR logging while drilling and also lesson learnt of what can be done of formation pressure while drilling on reservoir evaluation in vuggy carbonate reservoir.
