Integration of Basin Modeling and Geomechanics for Stress and Fracture Prediction —A Case Study From the Lower Magdalena Valley Basin (Colombia)

Abstract

Petroleum systems modelling is presented as an alternative to reduce the uncertainty of geomechanical reservoir analysis and to improve stress and fracture prediction. Instead of the a priori assumptions concerning mechanical properties and pore pressures commonly used in static geomechanical models, or relying on geostatistical extrapolation, incorporation of the subsidence-maturation-migration history, regional facies maps and variable paleo-stress fields can provide process-based geomechanical input parameters and boundary conditions for modeling. We performed a 3D geomechanical assessment of a tight gas reservoir in Northern Colombia. The methodology combines petroleum system technology and geomechanical modelling to provide enhanced input parameters, in particular, mechanical properties and pore pressure, for mechanical analysis. Initial data comprise the present-day subsurface geometry such as horizons, faults and facies maps derived from seismic and borehole data. The geological evolution of the reservoir since the basin origin, 39 Ma Ago, was reproduced using basin evolution and petroleum systems technology. Each horizon required the definition of deposition, erosion or hiatus. For each lithology thermal, hydraulic and mechanical parameters were assigned, based on the main rock components. Mechanical properties were derived as a porosity function. Boundary conditions, such as the prescribed subsidence/uplift history, paleo-geometries, basin heat flow and regional stress field data were considered. Extensive calibration was executed including well log data, rock mechanics laboratory results, geochemical information from core samples and hydraulic fracturing tests. Main results include data volumes for present-day Young’s modulus, Poisson ratio, pore pressure and all components of the 3D stress tensor. Local stress rotations are captured by the model. Results showed a good correlation with field measurements derived from wellbore logging, laboratory and core data. Implementation of this methodology proves itself as an enhancement in the geomechanical assessment at reservoir scale and shows the importance of understanding the reservoir evolution through time, leading to more accurate and reliable stress and fracture predictions that can be used for further exploration and production-related issues.

AAPG Datapages/Search and Discovery Article #90350 © 2019 AAPG Annual Convention and Exhibition, San Antonio, Texas, May 19-22, 2019