Unconventional hydrocarbon resources are becoming a major factor in changing the world energy picture. Fluid, rock, and rock-fluid properties play a key role in the optimal development and management of these unconventional reservoirs and their long term performance. Furthermore, complexity of rock-fluid properties and their stronger interdependence in shale reservoirs render characterizing fluid flow in nano Darcy reservoirs a formidable task. Fluid thermodynamics and the physics of flow characterization in nano pore systems differ significantly from that encountered in conventional reservoirs. The PVT models should properly account for the impact of high capillary pressures and/or surface forces encountered in nano-pores for reliable reservoir performance prediction. The flow modeling should capture accurately fluid distribution and compositional variability in the pore system and multi-phase flow characteristics in a wide range of pore / pore-throat size and wettability characteristics.
This paper presents a methodology for proper characterization of key rock and fluid parameters and their uncertainties through laboratory and Lattice-Boltzmann simulations and their impact on performance prediction through parametric reservoir simulation studies on a sector model. The impact of bubble point pressure suppression and the associated viscosity, oil FVF, and solution GOR changes on reservoir performance was captured through sensitivity studies in the simulation. Relative permeability models were developed based on pore-level flow simulation through Lattice Boltzmann. These models used in the simulation were further scaled-up to the end-point relative permeability data from core measurements.
A sector model consisting of a network of hydraulic and natural fractures imbedded in the matrix was built to study the sensitivities to fluid and rock properties such as bubble point suppression and the altered PVT property behavior, relative permeability, capillary pressure, and the matrix and fracture properties. Sensitivity runs allowed comparisons of initial rates and ultimate recovery, impacted by the critical rock and fluid data including effective permeability, its alignment with hydraulic and natural fracture network, rock-type based compaction, unconventional PVT behavior such as suppressed oil bubble point pressure and the resultant viscosity and GOR behavior, interfacial tension (IFT) /capillary pressure, and the relative permeability.
Unconventional shale reservoirs contain a wide range of fluids from dry gas to rich condensates and volatiles and in some cases, more viscous heavy oils. The shale reservoirs containing rich condensates and volatile and black oils often referred to as Liquid Rich Shale (LRS) reservoirs are prime targets in recent years because of huge resource potential and high economic benefits. However, a step change in existing conventional technologies is necessary in order to efficiently develop and manage these unconventional resources posing complex issues and unique challenges.