Formation Evaluation Challenges of Tight and Shale Reservoirs. A Case Study of the Bakken Petroleum System
Authors: Mellal I. , Rasouli V. , Dehdouh A. , Letrache A. , Abdelhamid C. , Malki M. L. , Bakelli O. 
Published: September 2023

Several challenges are associated with enhancing oil and gas recovery from tight and shale reservoirs, which make up a significant portion of hydrocarbon production worldwide. Despite past efforts to characterize the properties of these reservoirs using different techniques, several geological, geochemical, and geological properties of such formations remain challenging to determine accurately. To investigate these challenges, the Bakken Petroleum System (BPS) is taken as a case study, consisting of two source rock units and two tight reservoir units. A petrographic analysis using core slabs was done and a petrophysical model was built using conventional and advanced logs to estimate properties such as porosity, permeability, water saturation, mineralogy, movable and irreducible fluids, and pore size distribution. Challenges arise from the complexity of the formation, limitations of logging tools, and inaccuracies in estimation methods. Thin laminas and borrowed intervals are difficult to detect from well logs, leading to an incorrect reading of different well logs. Additionally, cementing material and variable volumes of minerals along the reservoir interval make the estimation of cementing exponent constant inaccurate. The salinity of water, dispersed clays, and clays coatings on grains lead to low resistivity readings. Also, permeability is independent of porosity and controlled by uniform pore throat and body size distribution. The study presents lessons learned from characterizing the complex BPS and challenges that can be used to accurately characterize other tight and shale reservoirs worldwide.

INTRODUCTION

Unconventional reservoirs are increasingly explored and exploited as conventional reserves decline. Shale and tight reservoirs account for 42% of total U.S. hydrocarbon reserves (EIA). Despite these huge reserves, less than 10% of the original oil in place (OOIP) can be technically and economically produced from these reservoirs using multistage hydraulic fracturing due to the low porosity and permeability, complex pore structure, and high variation in the mineralogy of these reservoirs(Abdeldjalil et al., 2023; Helms et al., 2023; Merzoug et al., 2022; J. Sorensen et al., 2014). Several enhanced oil recovery methods have been tested to investigate the factors affecting oil recovery from pore to field scale. This requires detailed understanding of rock and fluid properties at different scales for accurate modeling of subsurface fluid flow for EOR and gas storage (J.A. Harju, et al. 2022). Multiple challenges prevent accurate evaluation of the reservoir's rock and fluid properties distribution. This is due to various pore size and type distribution, mineralogy variation, different cementing minerals, thin beds, bioturbations, and existence and distribution of organic matter (Onwumelu et al., 2021). Geologic, petrographic and petrophysical analysis are the main common methods used to characterize reservoirs at different scales, This involves the identification of the main geologic features (grain size distribution, bioturbations, laminations and lithofacies), petrophysical properties (porosity, permeability, fluids, kerogen, and minerals volumes, pore size distribution), and pore characteristics (pore type and size, pore throat size distribution, grain sorting, and cementing materials). The accuracy and applicability of these methods are highly dependent on the scale of evaluation and the complexity of the reservoir.