Critical Role of Rock and Fluid - Impact on Reservoir Performance on Unconventional Shale Reservoirs

Unconventional hydrocarbon resources are changing the world energy picture. Fluid, rock and rock-fluid properties play a key role in developing and managing unconventional reservoirs and their long-term performance. The complexity of rockfluid properties and their strong interdependence in shale reservoirs make it difficult to characterize fluid flow in nano-Darcy reservoirs. Furthermore, fluid thermodynamics and flow characterization physics in nanopore systems differ significantly from those encountered in conventional reservoirs. To generate reliable reservoir performance predictions, PVT models should account for the impact of high capillary pressures and/or surface forces encountered in nanopores. Flow modeling should accurately capture fluid distribution and compositional variability in the pore system as well as multiphase flow characteristics in a wide range of pore/pore-throat size wettability. This paper presents a methodology for: 1. Characterizing key rock and fluid parameters and their uncertainties through laboratory and Lattice-Boltzmann simulations. 2. Characterizing the impact of these parameters on performance prediction through parametric reservoir simulation studies on a sector model. The impact of bubble point pressure suppression and the associated viscosity, oil formation volume factor (VF) and solution gas oil ratio (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 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 embedded in the matrix was built to study the sensitivities of fluid and rock properties such as bubble point suppression, the altered PVT property behavior, relative permeability, capillary pressure, and the matrix and fracture properties. Sensitivity runs allowed for comparisons of relative performance predictions of initial rates and ultimate recovery, impacted by the critical rock and fluid data, including: effective permeability, its alignment with the hydraulic and natural fracture network, rock-type based compaction, unconventional PVT behavior (e.g., suppressed oil bubble point pressure and the resultant viscosity and GOR behavior), interfacial tension (IFT) and capillary pressure, and relative permeability. Introduction Unconventional shale reservoirs contain many fluids ranging 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 are often referred to as liquid rich shale (LRS) reservoirs. These reservoirs have been prime targets for development in recent years because of their huge resource potential and high economic benefits. However, a change in existing conventional technologies is necessary to develop and manage these complex and unique unconventional resources efficiently. Over the past decade, significant progress has been made in understanding geological, geo-chemical, geo-mechanical, petrophysical and rock and fluid characterization of unconventional plays (Clarkson et al. [2011] and Orangi et al. [2011], Honarpour et al, [2012], Bertoncello [2013]) This article explores new insights and novel ways to characterize key rock, fluid and rock-fluid properties, highlighting their relative significant impact on performance predictions. LRS reservoirs have the following general characteristics (Clarkson et al. [2011]): URTeC 2013 Page 1230