Mitigating Reservoir Property Uncertainty and Identifying the Boundary between Conventional and Unconventional Reservoirs: An Integrated Case Study from Mature Fields in the South Sumatra Basin, #20479 (2020)

It is not uncommon to observe production (test) results that deviate from geological and geophysical reservoir study prognosis. More interestingly, this behavior is observed even when the log characters appear similar to offset or existing wells. Our experience in the South Sumatra Basin indicated in some wells, reservoirs that were thought to have relatively poor rock quality and low flow potential were reported to yield relatively moderate oil production, while vice versa: better-quality reservoir rocks reported oil rate that was below expectations, even lower than its perceived poorer (based on standard log signatures) rock quality counterpart. Wells with minimum pay zone (as indicated by petrophysical evaluation results) were able to produce reasonable initial oil rate while wells with relatively thicker pay zones produce only similar or lower oil rate with some or significant water cut. Interestingly this phenomenon is observed not only on a single field but also on neighboring and other fields in the South Sumatra Basin. Over time this is also supported by years of sustained oil production and surveillance data during the development phase of such fields. This phenomenon has traditionally been regarded as complexity or uncertainty in reservoir property description and left without significant further research into investigating the cause and implication of such phenomenon within the context of overall understanding of hydrocarbon presence and distribution. Given this background, we have performed a preliminary study revisiting the properties of reservoir and non-reservoir sections from three oil fields (Jirak, Tanjung Miring Timur, and Belimbing) in the South Sumatra Basin. The study makes use of actual rock samples and well datasets from different sources; the primary being core and logging datasets, supported by production (test) results as they provide direct measurements of rock (static and dynamic) properties. Geological and petrophysical information resulting from a range of routine and special core analyses measurements are incorporated in this study. Biostratigraphic, petrographic, XRD, and TOC data from special core analysis measurements are used to provide static descriptions of reservoir properties. The core datasets are complemented by a range of logging datasets including nuclear magnetic resonance (NMR) and multi-source acoustic logs. Correspondingly, porosity, permeability, capillary pressure and relative permeability data from routine and special core analysis measurements as well as fluid PVT data are examined to provide dynamic descriptions of reservoir properties. Subsequently, the existing geological concept such as regional petroleum system as well as stratigraphic correlations are revisited and integrated in the study. A revisit of regional seismic data is also performed but mainly to validate the stratigraphic correlations made in this study. The fields being studied are producing fields with production data spanning over 50 to 90 years. This is interesting data which also serves as an important calibration point to validate any new geological and petrophysical understanding resulting from this study.