The successful application of enhance oil recovery (EOR) technology requires an accurate understanding of the internal architecture of reservoirs and complex distribution of flow unit characteristics within different lithofacies. However, flow unit characteristics in the reservoir lithofacies of West Baram Delta Offshore, Sarawak, remain unexplored. Therefore, this paper investigates potential hydraulic flow units (HFUs) present within the five (5) identified sandstone lithofacies using thin sections, scanning electron microscopy (SEM), two-dimensional (2D) petrographic image analysis and helium porosimetery. The identified lithofacies include massive coarse-grained sandstone (MCGS), massive medium-grained sandstone (MMGS), massive fine-grained sandstone (MFGS), massive friable fine sandstone (MFFS) and massive very fine grained sandstone lithofacies (MVFGS). A plot of reservoir quality index (RQI) against normalized porosity (фz) showed five main hydraulic flow units (HFUs) within the identified lithofacies. The MFGS, MFFS and MVFGS lithofacies exhibited moderate to high matrix fractions and moderate to poor sorting, suggesting high tortuosity and hence characterized by low flow zone indicator (FZI). On the other hand, the MCGS and MMGS lithofacies exhibit very low to low matrix fractions, medium to coarse grain sizes and moderate to well sorting, signifying lower tortuosity, and hence characterized by relatively higher flow zone indicator (FZI). Thus, a hydraulic flow unit (HFU) can be formed by more than one lithofacies that exhibit similar fluid characteristic attributes, regardless of the difference in depositional environment and diagenetic processes undergone. This study concludes that HFU scattered plot can serve as a qualitative model for the characterization of flow unit characteristics in a well-comprising different lithofacies, particularly for field development plans in the West Baram Delta. Keywords Rock fabric • Flow unit characteristic • Flow zone indicator (FZI) • Reservoir quality index (RQI) • West Baram Delta * I. Yusuf
The Nigerian Petroleum Industry Act (PIA) passed into Law in 2021 has the major goal to reform the Nigerian petroleum sector operations into policy, regulations and business (commercial). In the line of this, the Nigerian National Petroleum Corporation (NNPC) was transformed to NNPC Ltd to operate entirely commercially with a supervising Board and registration with the Corporate Affairs Commission. Such a commercial mandate will entail the need to explore and produce more oil and gas for export and domestic utilization. Oil is becoming less attractive as an energy source but gas is gaining momentum as a clean energy source in the global energy transition road-map. The global energy transition road-map is drawn around clean, alternative and renewable energies. The Nigerian frontier basins have recently come on board as new business opportunities with huge petroleum gas resources. These frontier basins comprise the Anambra, Benue, Bida, Chad (Nigerian sector), Dahomey, and Sokoto Basins as well as the Deep and Ultra-deep offshore. Maturing these basins through data generation and production of the gas resources therein will promote the nation’s gas utilization and gas expansion programmes meant to promote industrialization and huge employment generation, grow the economy and engender positive social transformation. The clause in the PIA that promotes frontier exploration is well-thought out. Available and required geological data needed to mature the frontier basins to producing basins are presented in this paper. The success made in Kolmani River-2 well discovery is a case study.
Reservoir property modeling is often used to determine lateral extent and continuity in targeted multiple wells for implementation of any enhanced oil recovery (EOR) methods. Some works were reported that most of EOR techniques are controlled by static-dynamic lateral extent and continuity within reservoir pay zones succession as they contribute to poor recovery in fields. Therefore, delineation of lateral extent and continuity using a statistical approach could save time, less cumbersome and data required. This paper by cluster analysis delineates lateral extent of 5 exploratory wells by integration of microscopic petrographic and petrophysical data from 132 subsurface and 97 core plugs. Result reveal four main petrofacies clusters of good lateral extent and continuity that corresponds to section (Blue cluster) characterized by massive coarse grained sandstones, massive fine grained sandstones and massive very fine grained sandstone lithofacies with average porosity (18-32%), permeability (400-1189 mD) at depths between 859 and 2129m. The Green cluster is dominated by massive fine grained and massive medium grained sandstone lithofacies exhibit average porosity (15-30%), permeability (110-840 mD) at depth from 880-1805m, while Brown cluster comprises of massive medium grained and massive fine grained sandstone lithofacies exhibit an average porosity (18-25%) and permeability (210-657 mD). The understandings of porosity-permeability continuity can facilitate effective areal sweep efficiency from injected fluid well to production well during recovery. Thus, this approach is important to improve the field plan for reservoir engineers.
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