ATTRIBUTE-DRIVEN FLUID REPLACEMENT MODELING AND RESERVOIR CHARACTERISATION OF TETEMU FIELD, ONSHORE NIGER DELTA, NIGERIA

Abstract

Change in saturation levels occurs in reservoirs during hydrocarbon production resulting in fluid replacement. This impacts on the mechanical and elastic properties of reservoirs and consequently, alters production model and forecast. Increasing occurrence of altered production model has necessitated the need to understand how these properties can trigger fluid replacement in hydrocarbon reservoirs. Mechanical and elastic properties can be harnessed to constrain Fluid Replacement Modeling (FRM) in two scenarios: increasing water and gas saturations (Sg) at various reservoir conditions. This research was designed to produce geological model to predict the responses of rock properties to fluid replacement and reservoir behaviour. The FRM and reservoir characterisation were carried out using petrophysical and rock-physics analyses of wells A1, A2 and A3 of Tetemu Field, onshore Niger Delta. Petrophysics was employed to determine lithology, Net-Gross Ratio (NGR), shale volume (Vshale), porosity (ɸe) and saturations which were estimated by Gamma Ray (GR), neutron-density and resistivity logs. Depositional environments were deduced by GR signatures. Rock-physics was used to determine reservoir’s stress state, elastic and mechanical properties’ responses to increasing saturation. Young (E), Bulk (K) and Shear (G) moduli, Unconfined Compressive Strength (UCS), Compressibility (Cb) and Poisson ratio (ʋ) were derived from elastic properties such as Compressional wave velocity (Vp). Sand production potentials were estimated using G/Cb. Four hydrocarbon reservoirs (A, B, C and D) were delineated. The NGR reduces from proximal to distal due to reduction in depositional energy. The reservoirs were relatively clean with Vshale less than 15.0% threshold. The Vshale increased in the direction of lower hydrodynamic flow. Reservoirs were deposited in fluvial channel, progradational and deltaic sands. Dynamic Rock Physics Template (RPT) showed pore pressure depletion in reservoirs A and D of A1 as well as A, B and D of A2. The density increase was attributed to increasing G and K when brine replaced hydrocarbon. Unconventional attenuation of Vp from 3.09-3.04, 3.13-3.08, 3.92-3.86, 3.53-3.49 and 3.87-3.80 km/s in A of A1 and A3, and D of A1, A2 and A3, respectively, were due to dissolved gases. The values of E and K increased exponentially from 21.45-21.67 GPa and 16.93-18.28 GPa in A of A2. The value of ʋ was higher in oil and brine but negligible in gas-sand. The G/Cb for all reservoirs were greater than 0.8×1012 psi2 threshold. Increasing Sg resulted in reduction in E and UCS. The observed pore pressure depletion from RPT could cause well instability due to induced matrix stress. Anomalous behaviours of elastic parameters were attributed to dissolved gases, while a decrease in UCS and E in A and D of A1 and A3 will cause wellbore collapse. None of the reservoirs produced sand during hydrocarbon production. Enhanced recovery modeling generated decreased K and E which reduced the stiffness and brittleness of the reservoirs. Unconventional attenuation of compressional wave velocity and the responses of bulk modulus in gas provided a pathway for prediction of reservoirs’ responses to changing fluid saturations during hydrocarbon production. These models could be employed as templates for monitoring hydrocarbon reservoir performance.