Unconventional tight reservoir sands have low porosity and very low permeability (mostly less than 0.1mD) due to their fine grain size and poor grain sorting that is often exacerbated by extensive diagenetic effects such as cementation and compaction. Petrophysical evaluation in these formations is very challenging. Conventional downhole logs such as density, neutron, sonic, gamma ray and resistivity measurements provide limited information on pore size variations and often missed Key geological features especially at the early stages of reservoir development. Fluid characterization at the earliest possible stage is paramount to guide the development of these reservoirs where tight well spacing, stimulation (fracturing) and or horizontal well completion is usually required. The main objective of this paper is to show a process of fluid characterization in unconventional tight sand that guides reservoir stimulation. Porosity partitioning using nuclear magnetic resonance (NMR) logging data helps address these challenges in three distinct steps. First, the 1-dimensional (1D) NMR T2 spectrum quantifies the amount of bound and free fluids pore space and reveals reservoir quality with unique sensitivity. In this step, the NMR fluid substitution method was utilized to ensure consistency between NMR logs in oil-based mud (OBM) and water-based mud (WBM) systems. Second, the free fluids are further subdivided into hydrocarbon and water phases using a 2-dimensional (2D) NMR T1/T2 processing technique. Third, the hydrocarbon phase is subdivided again into liquid and gas phases where a gas flag is turned on whenever the NMR gas signal significantly exceeds measurement uncertainty. This enables detection of live hydrocarbons with high gas-oil ratio (GOR). This paper presents the integration of NMR analysis into petrophysical evaluation of an unconventional tight sand reservoir. The evaluation helped optimize the best interval for stimulation. Fluid sample acquired with formation tester correlated very well with NMR log-based fluid prediction. Integrated NMR analysis, including bound fluid vs. free fluid analysis and 2D NMR-based fluid characterization, including gas indicator flag, was applied to establish the presence and type of hydrocarbon in tight sands and select the best representative interval for stimulation. The continuous reservoir quality and fluid distribution profiles provided by these logs were beneficial for the geological understanding and complex formation testing operations in this challenging reservoir.

Saudi Aramco's first deepwater exploration well targeted a sub-salt Miocene syn-rift section located in over 2,000 ft of water and beneath 9,000 ft of halite and evaporites. Offset well information from previous shallow exploration wells was limited; therefore, calibration for pre-drill pore pressure and fracture gradient prediction (PPFG) was performed using a single shallow water well completed two months prior to spuding the well. Pre-drill PPFG predictions presented a very high degree of uncertainty, which translated into uncertainty in well design and mud weight planning. Pre-drill pore pressure prediction relied on seismic velocities extracted from a wide azimuth 3D survey and used Residual Normal Move Out (RNMO) and seismic inversion to extract velocities that were presumed to represent shale velocities. Real-time pore pressure monitoring was based on a comprehensive program that included logging while drilling (LWD), multiple look-ahead vertical seismic profiles (VSPs), velocity model updating and rapid remigration (pre-stack depth migration) around the wellbore to produce simultaneous improvements in imaging and depth estimates that were tied back to an evolving geological pore pressure model. Significant differences between the pre-drill pore pressure model and measured well pressures highlight the critical importance of the pre-stack depth migration (PSDM) velocity model and the necessity to be able to modify the seismic velocity model and calculated pore pressures in real time to provide accurate information to drilling operations. An integrated team of technical professionals from nine separate departments was required to successfully carry out this project, which resulted in the successful drilling of a deepwater well in a high overpressure -low fracture gradient environment with minimal operational downtime. Geological Setting and StratigraphyOpening of the Northern Red Sea rift began approximately 25 MaBP as the Arabian platform began to move east (25-15 MaBP) then northeast (15-0 MaBP) relative to the African craton. Initiation of the Northern Red Sea rift triggered the onset of syn-rift deposition into a series of graben and half graben basins that continues to present day. The deepwater (beyond 1,000 ft water depth) syn-rift stratigraphy consists of Oligo-Miocene sediments up to 21,000 ft thick deposited under varied depositional environments and settings that are related to the macro tectonic evolution of the rift system. In terms of