Journal of Petroleum Technology June 2012 : Page 30
TECHNOLOGY UPDATE to apply resistivity independent satu-ration measurements, such as nuclear magnetic resonance (NMR) and dielec-tric porosity. These allow direct mea-surements of total fluid-filled porosi-ty (NMR T 1 time constant dimension) and total water-filled porosity (dielec-tric). The difference between the two is typically unflushed oil and gas that is picked up in TOC pyrolysis data as an S 1 free hydrocarbon volume. It should be noted that the accuracy of the dielectric water porosity measurement depends on determining the mineralogy and water salinity. The NMR porosity data is best viewed in a T 1 dimension, as that time constant spreads out the measured porosity spectrum to twice the extent of that seen in conventional T 2 porosity measurements. This allows a much more detailed analysis of the ultrasmall pores in the lowest part of the spectrum. Recent laboratory data show that in ultrasmall pores, gas exists in a restricted diffusion environment and will be detected ear-lier in a normal water signal range and not later in a T 1 bulk signal. Even with that, a T 1 measurement gives the analyst a much more robust spectrum in which an enhanced spectral BVI technique can be used to discriminate clay-and capil-lary-bound water from small amounts of free fluid. The wet rock volumetric analysis can directly use all the discriminated NMR and dielectric porosity measurements. Clay-bound water can be constrained to what is seen from NMR. Total water can be constrained by a total dielectric poros-ity. A solved oil or gas volume can be constrained to the difference observed between NMR and dielectric porosities. from DTC and DTS dipole sonic data and are calibrated to static rock proper-ties using surface core stress tests and analysis from small volume diagnostic fracture injection tests (DFIT) in cased vertical exploration wells. After final cali-bration to the DFIT analysis, the program determines fracture initiation pressure, fracture closure pressure, and closure stress gradient. Since 2008, we have used the con-cept of shale “brittleness,” a simple ratio between Young’s modulus and Poisson’s ratio, as a technique to predict induced fracture complexity and enhanced sur-face area contact. It has been used exten-sively as a powerful fracture fluid system design tool and to aid in sweet-spot iden-tification. This same technique is imple-mented as “pseudobrittleness” and is color palette calibrated to core-measured brine hardness. Using directly measured DTC and DTS values, calibrated synthetic DTC and Mechanical Properties and Brittleness Conventional vertical Young’s mod-ulus and Poisson’s ratio are calculated SPE Hydrocarbon Economics and Evaluation Symposium 24–25 September 2012 Calgary, Alberta, Canada www.spe.org/events/hees 30 JPT • JUNE 2012
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