Abstract

Field A is located offshore of Peninsular Malaysia, consists of multi stacked reservoirs where previously the vertical communication between different units was considered to be well understood. Separate reservoir models were built independently where fair to good history matching were achieved during the dynamic modelling study. Subsequently two drilling campaigns were executed based on the simulation results. On top of that, regular reservoir surveillance and frequent simulation model updates have assisted in assessing vertical connectivity.

North of Field A, a recent drilling campaign in early 2019 indicated possible communication between infill wells in Unit 35U and water injectors in Unit 35L. One of the well is experiencing severe watercut production than initially forecasted. It is well understood that the seismic amplitude for Unit 35L is being overlapped by the stronger response of Unit 35U in the northern area. Due to that, the reservoir modelling and understanding for Unit 35L in this region is mainly driven by actual well controls and the geological model, rather than from seismic.

Meanwhile in the Southern area, a stable reservoir pressure trend is observed in Unit 27 despite reduction of cumulative voidage replacement ratio (VRR) from 0.6 to 0.4. Additionally well C02ST1 was producing oil at an increasing rate, a trend which the current reservoir model failed to match. The model also failed to explain the unreasonably high recovery factor (RF) of 50% for Unit 27 given the delayed water injection and small gas cap support.

Back to the North, well interference testing was conducted by shutting in water injectors in Unit 35L and observing the pressure response of a new well in Unit 35U using a permanent downhole gauge (PDG). Observations indicated a decrease in pressure response once injection was turned off, confirming the communication between the two units. Moving forward, two injectors for Unit 35L will be temporarily suspended to relax the watercut trend in the new wells, thus improving the oil rate.

In the South, a material balance study and reservoir 3D model suggest additional volume needs to be introduced for Unit 27, which indicates that it is probably draining Unit 35U oil due to a higher level of vertical communication and overlapping sand bodies between both units. This is also supported by produced water salinity readings of well C02ST1 (Unit 27) having similar values as Unit 35U wells rather than other Unit 27 wells.

Communication between different layers often requires longer time and a significant amount of production to be well established and observed. This case study proves that reservoir understanding can still be a mystery even when the field is reaching 20 years of production.

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