Methods of deriving rock properties from log and core measurements and the effect of various parameters on resulting moduli and stress estimates are examined. The paper also discusses the effects of rock anisotropy and inhomogeneity on static and dynamic properties. The impact of organic materials and trapped gas on sonic logs and conventional mechanical properties interpretation and the use of synthetic sonic logs are also presented. For static and dynamic measurements on core samples, the effects of the condition of recovered core and applied laboratory procedures on measurement results are also considered.
Potential errors resulting from the use of inappropriate mechanical properties for stress profiling and fracture geometry prediction can be significant. The paper identifies common pitfalls in core and log interpretation. A recommended procedure to determine useful and accurate rock mechanical properties for stress profile prediction and fracture design is presented.
Introduction
Full-waveform sonic logs and core measurements are commonly used to derive "calibrated?? models of in-situ stress profiles. The results are used as input to hydraulic fracture design simulators, which are used to determine optimum perforation placement, job size, pump rate, fluid and proppant requirements, and other design variables for optimum reserve recovery. The methods used to determine rock mechanical properties and stresses assume that the raw input measurements are valid and that the conditions of measurement are appropriate to conditions during hydraulic fracturing. In unconventional reservoirs, these assumptions may not be valid.
Because of the potential for large reserves, there is an increasing interest in unconventional reservoirs. For the purpose of this discussion, unconventional reservoirs are considered to be tight and ultra-tight gas sands (less than 0.01 md effective permeability), gas-shales, and coalbed methane (CBM) reservoirs. These reservoirs have several characteristics in common: They all have low, very low, or nearly immeasurable "matrix?? permeability. They may be self-sourcing and can contain organic carbon within the hydrocarbon maturation window, and may be actively generating hydrocarbons at the time of discovery and development. Many have abnormal pore pressures, relative to a hydrostatic gradient. Many occur in regions with significant tectonic stress or strain overprints, hence anisotropic stress fields. Production from these reservoirs is commonly enhanced through the presence of some kind of fracture or micro-fracture network.
These complexities affect the behavior of core and log measurements. Interpretation of core and log data may require different paradigms and assumptions than those commonly applied in more conventional reservoir systems. Using conventional assumptions when dealing with measurements in unconventional reservoirs can lead to significant errors in the derived rock mechanical properties and estimated stress profile. These errors can lead to incorrect predictions of fracture containment and overall geometry, conductivity, and post-frac performance.
