Rock typing and hydraulic flow units as a successful tool for reservoir characterization of Bentiu-Abu Gabra sequence, Muglad basin, southwest Sudan
Introduction
Muglad basin is a main part of the huge Cretaceous rift system that extends within the central and western African rift system (McHargue et al., 1992; Makeen et al., 2016). It is controlled by some regional fault trends and analogous fracture zones. The structural systems of this basin are dominated by NW-SE trending faults that are parallel to the basin axis (Fairhead, 1988; Schull, 1988; McHargue et al., 1992).
The mineral composition of sedimentary rocks is a reflection of the effect of more than one factor as provenance, sedimentary environment and the diagenetic processes which have the main implementation on the reservoir properties (Raymond, 2002). Petrophysical analysis can be used as a successful tool for reservoir characterization and classification of different pore types (De Ros and Goldberg, 2007; Kassab et al., 2017a, b). Consequently, the main purpose of this study is to estimate the hydrocarbon potentiality of the Early Cretaceous Bentiu and Abu Gabra formations in block-4 of Muglad basin in Sudan (Fig. 1, Neem North-2 well). This could be achieved by interpreting the available conventional well log data sets integrated with the conventional and special core data, and the sedimentological studies of these intervals including petrographical, and SEM studies.
Discriminating the studied sequence into a number of reservoir rock types (RRTs) or hydraulic flow units (HFUs) and studying impacts of the mineral composition and the dominant diagenetic factors on their potentiality is essential to achieve a precise reservoir modeling. For the present study, the reservoir rock type is a term referring to a set of samples that are characterized by similar mineral composition and petrophysical behavior, i.e. porosity values of the different samples have the same contribution to their permeability values.
The HFU concept of Amaefule et al. (1993) was applied to the available core intervals and then summing up reservoir units having the same petrophysical properties into one hydraulic flow unit (Maglio-Johnson, 2000; Nabawy et al., 2018a, 2020). Each HFU has a unique range of flow zone indicator (FZI) and reservoir quality index (RQI) values. A number of reliable mathematical equations were also introduced to enable prediction of the reservoir quality parameters of the different HFUs in the uncored intervals (Nabawy et al., 2018a).
The average detected petrophysical characteristics as volume of shale (Vsh), effective porosity (Øe), water saturation (Sw), hydrocarbon saturation (Sh) and net-pay thickness have been calculated from well log data using the appropriate software. In addition, the reservoir parameters (density, porosity, and permeability, as well as water and oil saturations) were calculated from core data and applied for reservoir ranking.
Section snippets
Lithostratigraphy and depositional environments
Muglad basin is considered as one of the largest continental rift basins in the Sudan's interior where several prospective petroleum reservoirs have been discovered. It is one of the most important west and central African rift basins in Sudan which are represented by full grabens and discrete half grabens (Fig. 2) (Mohamed et al., 1999; Zhang and Gu, 2011; Dou et al., 2013; Makeen et al., 2015a, b).
It has been formed due to an extensional structural movement in the dextral shear stress event
Methodology
Indeed, well log analysis is deemed as a powerful method to evaluate the petrophysical characteristics of the reservoir sequences. It involves estimation of effective and total porosity values, and shale volume, in addition to water and hydrocarbon saturations. The present well log study concerns with interpreting a complete set of the available conventional logs of Neem North-2 well which is located in block-4 of Muglad basin in South Kordofan, Sudan. The petrophysical parameters of Bentiu
Well log analysis
Plotting the raw data of the studied Bentiu Formation indicated that the gamma ray of the studied sequence is relatively overestimated, and can't be applied for estimating the shale volume. Therefore, the shale volume of the studied sequences was estimated using the neutron-density technique. In addition, plotting the well log data (not integrated with the core data and petrography) in a vertical plot indicated discrimination the sequences into seven zones (Fig. 4). On the other side, the
Permeability heterogeneity
Following the Dykstra-Parsons technique (1950), permeability values of the studied sequence are described as extremely heterogeneous (V = 0.91, Fig. 9). This may be attributed to the intercalation between the wacke and arenite facies which can be summed up into two rock types as mentioned from the petrographical study. This facies intercalation led to the complex connectivity of pore spaces, in addition to the amount, type and manner of distribution of the detected authigenic clay minerals and
Conclusions
Integrating the well log analysis, core data, and sedimentological studies are useful for discriminating the Bentiu-Abu Gabra sequences into two reservoir rock types (RRTs), and four hydraulic flow units (HFUs).
The well log data indicates that the average shale volume, effective porosity and hydrocarbon saturation are 31.6, 16.2, and 39.5% which are prospective values.
Petrographically, the studied sequence is described as; 1) quartz to subfeldspathic (subarkose) arenite, and 2) quartz to
Declaration of competing interest
The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.
Acknowledgement
The authors would like to thank the Greater Nile Petroleum Operating Co. LTD. (GNPOC), North Sudan. Also, they would like to thank those who offered help during sample preparation, measurements and data interpretation. The authors extend their sincere appreciation to the Researchers Supporting Project number (RSP-2020/92), King Saud University, Riyadh, Saudi Arabia. We would like also to thank the Editor-in-Chief Prof Dr Read Mapeo, the Associate Editor Prof Dr Mamdouh M. Abdeen, and the
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