PDO has a large portfolio of mature Gharif fields with significant hydrocarbon potential to be unlocked by efficient well and reservoir management (WRM). In 2016, focussed surveillance on Closed-in Wells (CIW) in a mature PDO South Gharif field, highlighted significant bypassed oil opportunity in Low Resistivity Pay (LoRP) reservoir –"C". Presence of conductive minerals and different clays in the LoRP sands, led to a pessimistic assessment of resistivity based hydrocarbon saturation. As such, histrocially, these oil bearing sands were not perforated. LoRP was production tested in 2 CIW & 3 New Oil (NO) wells in 2015, doubling field's net oil production (Figure1). Insights from historical field production, pressure depletion, core and Nuclear Magnetic Resonance (NMR) data were integrated to update the static subsurface model which led to an increment of 21% in the field STOIIP. Current inventory of high water cut (>95%) and high sand producing oil producers are being converted to dedicated LoRP producers on opportunity basis. This has reduced the frequency of expensive well workovers. Quick screening of LoRP has been initiated for all PDO South fields. Initial results show that similar bypassed oil opportunities exist in other mature brown PDO South fields as well. Broadly speaking, such bypassed oil opportunities can be attributed to one of the following subsurface mechanisms at play i.e. presence of thin sand- shale intercalations which are not vertically resolved on wireline logs, presence of condutive minerals e.g. pyrites or clays and high irreducible water saturation in microporous rocks. With the current low oil prices, re-exploration of mature fields by interpreting and maturing low resistivity pay reservoirs, presents an attractive business proposition.

The Buah formation has gained increasing interest in the search for new exploration plays in the Sultanate of Oman. Significant hydrocarbon accumulation has been discovered in the Buah recently. The Buah formation is complex in terms of lithology, pore structure, and the coexistence of oils with different gravities, including bitumen. The existence of bitumen makes it difficult to determine permeable and recoverable hydrocarbon intervals. The rock characteristics of Buah formation impose significant challenges to traditional formation evaluation methods. Because of the low porosity, error tolerance for estimation is low. Saturation determination using resistivity logs is uncertain because of low porosity and inexact Archie parameters. These include the cementation factor (m) that accounts for water phase connectivity, and the saturation exponent parameter (n), which is sensitive to rock wettability. The wettability status is unknown. However, the existence of bitumen could greatly influence the wettability and thus the saturation exponent. A formation evaluation workflow has been developed to provide accurate petrophysical parameters necessary to estimate stock-tank oil initially in place (STOIIP) and conduct static and dynamic modeling. The triple combo and elemental capture spectroscopy logs are first combined for the best total porosity estimate and lithology determination. Nuclear magnetic resonance provides a lithology-independent pore space hydrogen index, which improves the accuracy of the porosity estimate and also quantifies the bitumen-filled pore volume. Dielectric dispersion analysis provides water-filled porosity together with the water tortuosity exponent (mn) that is strongly related to the cementation factor that can be incorporated in resistivity analysis to obtain a better estimate of water saturation in uninvaded zone. Thus, the integration between nuclear logs and dielectric measurements enables the direct estimate of producible hydrocarbon. Conventional core analysis was used to categorize different rock types in this reservoir by using the reservoir quality index (RQI) approach. The results of our analyses have improved the static model, and examination against production logging and the dynamic model has revealed the best contributing rock types, the importance of fractures, and the impact of bitumen in hindering production.

Tight unconventional reservoirs have become an increasingly common target for hydrocarbon production in Oman. Exploitation of these resources requires a comprehensive reservoir description and a characterization program to estimate reserves, identify properties that control production, and account for fracturability. It is becoming evident, however, that any single technology by itself is unable to address all the key challenges, and the integration of technologies is crucial to answer all the questions to reduce key subsurface uncertainties. This paper discusses in detail a case study in which the integration of advanced petrophysical logs has enabled successful downhole sampling and provided a comprehensive reservoir and fluid characterization despite the very challenging lithologies and very tight formation. The comprehensive logging suite included advanced measurements of dielectric dispersion, nuclear magnetic resonance (NMR), and spectroscopy. The reservoir fluids and dynamic properties were also characterized by a series of formation testing measurements. Dielectric dispersion logs clearly identified the hydrocarbon-bearing zones despite the characterless resistivity profile, taking advantage of its resistivity-independent saturation approach. The accuracy of the measurement was key to estimating water- filled porosity down to 0.5 p.u. regardless of the formation water salinity and changes in the rock electrical parameters. The integration of dielectric and NMR measurements, reflecting the pore structure, has played a major role in identifying the "best" reservoir intervals and indicating the type of fluid (hydrocarbon or water) filling the free pore space. The NMR unimodal and bimodal T2 distributions revealed the pore structure along with polarization effects on light hydrocarbons, helping to gain insight on the reservoir quality. The NMR was also combined with the microimaging measurements to indicate pore connectivity and formation heterogeneity. This integrated approach was applied to a deep tight-gas exploration well and has contributed to achieving successful formation sampling that provided an in-situ fluid characterization despite the tightness of the rocks, with only 4 p.u. average porosity. Integrated logging measurements along with fluid sampling resulted in both enhanced formation and fluid characterization in this exploratory well, shedding light on the hydrocarbon potential over the region.