Development of unconventional oil and gas reservoirs, particularly the shale gas, gas-condensate, and shale oil, has gained tremendous momentum in recent years. Energy companies aggressively are adding unconventional hydrocarbon resources to their portfolios. The unconventional resources usually refer to ultra low permeability reservoirs that cannot be produced at economic rates or volumes without stimulation of near well-bore regions. New technologies of horizontal well coupled with staged hydraulic fracturing have made the development of these reservoirs an economic reality. But often, the initial attractive production rates decline fast and thus making them economically marginal and sometimes operationally unattractive. In order to efficiently produce these reservoirs, it is important to understand the flow mechanism and the controlling rock and fluid parameters that significantly impact the long term production performance of these resources.We have conducted detailed reservoir simulation studies to investigate the impact of rock and fluid properties and the drainage area of hydraulically fractured wells in a standard development pattern. The simulation of horizontal wells with 14-stage hydraulic fractures was conducted in a shale reservoir containing a wide spectrum of rock and fluid types, dry gas to gas-condensate, and oil. An extensive compositional reservoir simulation was conducted using both radial grid and sector model. Short term production data from several horizontal wells and long term production data from one vertical well were used for history matching and model calibration. A number of cases have been run with a wide range of fracture, matrix and fluid properties considering condensate banking, fracture patterns, pore volume compressibility, and relative permeability. The results showed• Cumulative oil production is sensitive to fluid properties, particularly to the GOR • Severe drop in productivity is observed due to matrix and fracture compaction and condensate banking • The drainage area and the contact area of the fractures with the reservoir are often limited in spite of extensive hydraulic fractures • Performance is also found to be sensitive to fracture permeability and matrix relative permeability • Fracture interference is limited and may occur in the late life of the reservoir

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.

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