The Unconventional Shale Reservoirs of Jafurah Basin: An Integrated Petrophysical Evaluation Using Cores and Advanced Well Logs
- Ghadeer Al-Sulami (Saudi Aramco) | Mohammed Boudjatit (Saudi Aramco) | Mohammed Al-Duhailan (Saudi Aramco) | Salvatore Di Simone (Saudi Aramco)
- Document ID
- Society of Petroleum Engineers
- SPE Middle East Oil & Gas Show and Conference, 6-9 March, Manama, Kingdom of Bahrain
- Publication Date
- Document Type
- Conference Paper
- 2017. Society of Petroleum Engineers
- 5.8 Unconventional and Complex Reservoirs, 5.1.1 Exploration, Development, Structural Geology, 5.6.1 Open hole/cased hole log analysis, 5.6.2 Core Analysis, 5.8.2 Shale Gas, 5.1 Reservoir Characterisation, 5.2 Reservoir Fluid Dynamics, 5.1 Reservoir Characterisation, 5.5.2 Core Analysis, 5.2 Reservoir Fluid Dynamics, 1.6 Drilling Operations, 5.6 Formation Evaluation & Management, 1.6.9 Coring, Fishing, 5 Reservoir Desciption & Dynamics
- Formation Water Saturation, NMR, SEM, Saudi Arabia, Shale gas
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The Jurassic mud rocks of Jafurah Basin are one of the most promising shale gas reservoirs in Saudi Arabia, retaining considerably high total organic content (TOC) values, and being the source rock for the world-class oil fields of the Kingdom. The purpose of this study is to build a calibrated model with core data using an integrated formation evaluation approach. The model then is frequently used to estimate reservoir properties, minimize uncertainty, and influence decisions on better well placements.
The Tuwaiq Mountain shale play is mainly composed of mudstone with few fraction of dispersed detrital minerals. The Tuwaiq Mountain Formation is divided into two parts: Upper and Lower, where the Lower Tuwaiq Mountain contains higher organic matter and so better reservoir quality as compared to the Upper Tuwaiq Mountain.
The formation evaluation of unconventional shale gas reservoirs presents numerous challenges. The conventional porosity logs, density neutron, and sonic, are heavily affected by the presence of organic matter. The estimation of initial hydrocarbon in place requires accurate estimation of formation water saturation. The conventional equations used to estimate the formation water saturation are subject to a high degree of uncertainty, mainly related to a complex wettability system and unknown formation water resistivity. Therefore, these challenges require the use of advanced and calibrated well logs. The advanced well log technologies used in this study are pulsed neutron elemental spectroscopy and nuclear magnetic resonance (NMR). The analysis can only be achieved through comparison and calibration with micro and nanoscale core data to help building an accurate petrophysical model. The use of the pulsed neutron elemental spectroscopy tool allows the estimation of rock composition, the evaluation of the amount of total carbon present in the system, and consequently, the amount of organic matter in the formation.
Natural magnetic resonance tools are lithology independent and provide an accurate estimation of total porosity. In unconventional shale gas intervals, the T2 distribution is mainly controlled by the surface relaxation factor, and so can be directly linked to the pore size distribution. By applying an appropriate cutoff, based on SEM results, continuous estimation of organic and inorganic porosity can be directly derived from NMR T2 distribution. A saturation model can also be built from a function, linking formation water saturation and organic carbon porosity. The core analysis data are used to understand the pore structure and calibrate the well logs.
The study has proven that the NMR technology works effectively in determining the total porosity, pore system distribution, and estimates of formation water saturation. The nanoscale core analysis is then used to understand the pore structure and to calibrate the well logs.
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