Development of HFU-based permeability prediction models using core data for characterisation of a heterogeneous Oligocene sand in the Nam Con Son basin

Core data by both routine and special core analysis are required to understand and predict reservoir petrophysical characteristics. In this research, a total number of 50 core plugs taken from an Oligocene sand (T30) in the Nam Con Son basin, offshore southern Vietnam, were tested in the core laboratory of the Vietnam Petroleum Institute (VPI). The results of routine core analysis (RCA) including porosity and permeability measurements were employed to divide the study reservoir into hydraulic flow units (HFUs) using the global hydraulic elements (GHEs) approach. Based on five classified HFUs, 16 samples were selected for special core analysis, i.e., mercury injection capillary pressure (MICP) and grain size analyses for establishing non-linear porosity-permeability model of each HFU based on Kozeny-Carman equation, which provides an improved prediction of permeability (R2 = 0.846) comparing to that by the empirical poro-perm relationship (R2 = 0.633). In addition, another permeability model, namely the Winland R35 method, was applied and gave very satisfactory results (R2 = 0.919). Finally, by integrating the results from MICP and grain size analyses, a good trendline of pore size distribution index (λ) and grain sorting was successfully obtained to help characterise the study reservoir. High λ came with poor sorting, and vice versa, the low λ corresponded to good sorting of grain size.

Marginal Field with Low Resistivity Pay Zone in Central Sumatra Basin: What We Can Learn

The XY field is a marginal oil field in the western part of the Central Sumatra Basin (CSB) and is covered by 3D seismic. The XY field started production in 2012. The oil originates from the Lower Sihapas sandstone reservoir, similar to other oil fields in the CSB. The Lower Sihapas sandstone as the primary reservoir in the XY field has overall gross thickness reaching up to 58 ft. Routine Core Analysis (RCAL) and Special Core Analysis (SCAL) are available from reservoir core interval in one of the wells. The reservoir consists of very fine to fine, well sorted sandstone, some pyrite, glauconitic and calcareous with thin layer of claystone and siltstone. The low and relatively high resistivity characteristics of the oil and water bearing zone respectively in the XY field becomes a unique challenge that partly causes an overestimation of the reserves. Prudent and detailed analyses for petrophysics and modeling in the XY field has been undertaken to re-evaluate and minimize errors. This paper will address some of the issues and causes related to low resistivity found in the main pay zone in the XY field as input for a strategic concept of finding and evaluating other exploration candidates surrounding the area.

Multiphase Flow Under Heterogeneous Wettability Conditions Studied by Special Core Analysis and Pore-Scale Imaging

Summary Wettability is a major factor that influences multiphase flow in porous media. Numerous experimental studies have reported wettability effects on relative permeability. Laboratory determination for the impact of wettability on relative permeability continues to be a challenge because of difficulties with quantifying wettability alteration, correcting for capillary-end effect, and observing pore-scale flow regimes during core-scale experiments. Herein, we studied the impact of wettability alteration on relative permeability by integrating laboratory steady-state experiments with in-situ high-resolution imaging. We characterized wettability alteration at the core scale by conventional laboratory methods and used history matching for relative permeability determination to account for capillary-end effect. We found that because of wettability alteration from water-wet to mixed-wet conditions, oil relative permeability decreased while water relative permeability slightly increased. For the mixed-wet condition, the pore-scale data demonstrated that the interaction of viscous and capillary forces resulted in viscous-dominated flow, whereby nonwetting phase was able to flow through the smaller regions of the pore space. Overall, this study demonstrates how special-core-analysis (SCAL) techniques can be coupled with pore-scale imaging to provide further insights on pore-scale flow regimes during dynamic coreflooding experiments.