Liquid-rich Shale (LRS) reservoirs are economically attractive but operationally challenging. Fluid, rock, and rock-fluid properties are critical for optimal reservoir development and management. Formation heterogeneity, fluid variability, and complexity of rock-fluid properties render fluid flow characterization a challenging task. Additional challenges associated with coring, fluid sampling and analysis include the recovery of quality cores and representative fluid samples, and timely acquisition of high quality data for making critical engineering design decisions. Rock and fluid analyses should be done in the following stages so that the critical data become available in a timely manner for making key decisions: a) ‘Wellsite Analysis’ including mineralogy/total organic content, TOC; b) ‘Quick Look laboratory analysis’ for detailed mineralogy and basic petrophysical properties; c) ‘Fast Track’ geomechanical, geochemical properties and petrophysical analysis on core plugs; and d) ‘Full Suite’ rock-fluid analysis for integrated studies. Low formation permeability, long transients, and contamination with OBM and fracturing fluid make acquisition of representative downhole or early surface fluid samples impractical. An alternative approach is to integrate mud gas analysis with light and heavy end components extracted from full diameter cores in canisters to reconstruct in-situ fluids. The PVT modeling should account for the impact of high capillary pressures encountered in unconventional shale reservoirs for reliable reservoir performance prediction. This paper presents the best practice methodology for characterizing critical rock and fluid properties, their variability and their impact on performance through parametric simulation studies. A sector model was constructed consisting of alternate TOC- and calcite-rich layers with a horizontal well placed in a calcite-rich layer. A network of hydraulic and natural fractures was implemented in the model to study the sensitivities to fluid and rock properties, relative permeability, capillary pressure, and fracture properties. It was found that the critical rock and fluid data impacting the initial rate and ultimate recovery were effective permeability, its anisotropy, its alignment with hydraulic and natural fracture network, rock-type based compaction, unconventional PVT behavior such as decreased oil bubble point pressure and the resultant viscosity and GOR behavior, interfacial tension (IFT)/capillary pressure, and relative permeability.

Acquisition of representative rock and fluid data from deepwater reservoirs is challenging and costly but is critical for the successful reservoir evaluation. It is common practice to use oil based mud, OBM, for drilling, particularly in deepwater offshore environment. Without proper mud additives and under excessive overbalance, OBM often invades the reservoir and contaminates cores and fluids. Measurements conducted on contaminated samples result in non-representative rock and fluid properties. Therefore, every effort should be made to minimize contamination in the samples. In fluids, mathematical corrections are needed to remove contamination effect and ensure representative fluid properties. In rocks, measurements on samples with minimum contaminations should be validated with those on cleaned samples.High OBM invasion in several cores showed elevated apparent in-situ water saturation as identified by visual examination, CT density mapping, residual brine analysis, and total liquid saturation calculation. Electrical resistivity measurement on "as-received" samples and simultaneous capillary pressure and resistivity measurements on cleaned samples provided correct in-situ water saturation determination.Customized sampling procedures with reliable fluid quality monitoring helped obtain minimally contaminated samples. In addition, novel mathematical techniques allowed correcting fluid samples to calculate representative fluid properties. Field examples are provided to demonstrate the success of these techniques for improved rock and fluid characterization.The results of this study demonstrate the need for reservoir engineers to be closely involved in fluid sampling, coring, and data acquisition stages employing rigorous QA/QC protocols. Customized sampling and coring programs were essential to obtain minimally contaminated rock and fluid samples and rigorous methodologies were critical to correct the data measured on the contaminated samples and determine representative rock and fluid properties. Introduction:Oil-based drilling fluids are in wide use because of their cost and time saving benefits, particularly in offshore environments and in drilling through troublesome shales and salts. The oil based drilling fluids (known as oil based mud, OBM and synthetic base mud, SBM) facilitate trouble-free and safe drilling operation with excellent shale inhibition, penetration rate, and well-bore stability. However, the use of OBM during drilling significantly impacts subsequent well operations such as RFT/WFT testing, coring and fluid sampling and may contaminate the core and fluid samples gathered if adequate steps are not taken to minimize the effects. In addition, obtaining representative rock and fluid data from the contaminated samples requires quantifying the contamination level and identifying a reliable methodology to correct for the effects. In this article, we discuss the critical issues, key challenges, and possible solutions to rock and fluid characterization using the data gathered on contaminated core and...

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.