Science

Relative permeability in shales is an important petrophysical parameter for purposes of accurate estimation of production rate and recovery factor, efficient secondary recovery, and effective water management. We present a method to estimate saturation-dependent relative permeability in shales based on the interpretation of the low-pressure nitrogen adsorption-desorption isotherm measurements. Relative permeability were determined for 30 samples from the gas — and oil — window of Eagle Ford and Wolfcamp shale formations. These sample have low-pressure helium porosity (LPHP) in the range of 0.04 to 0.09 and total organic content (TOC) in the range of 0.02 to 0.06. The samples were ashed to study the effects of removal of organic matter on the pore size distribution, pore connectivity, and relative permeability. The estimated irreducible water saturation and residual hydrocarbon saturation are directly proportional to the TOC and LPHP, and exhibit 15% variation over the entire range. Pore connectivity, in terms of average coordination number, decreases by 33% with the increase in TOC from 0.02 to 0.06. The estimated fractal dimension is close to 2.7 for all the samples. The estimated relative permeability of aqueous phase and that of hydrocarbon phase at a given saturation is inversely proportional to the TOC. Relative permeability curves of the hydrocarbon phase for geological samples from various depths in a 100-feet interval indicate that the hydrocarbon production rate will vary drastically over the entire interval and these variations will increase as the hydrocarbon saturations reduce in the formation. In contrast, relative permeability curves of the aqueous phase suggest limited variation in water production rate over the entire interval. Further, based on the relative permeability curves, the hydrocarbon production is predicted to be negligible for hydrocarbon saturations below 50% and the water production is expected to be negligible for water saturations below than 80%. Efforts are ongoing to use the laboratory-based estimates to predict field-scale production and recovery rates.

Measurements of fluid wetting characteristic are made routinely on rock samples. However, there are no published petrophysical models to differentiate between oil-wet and water-wet fractions of a reservoir sequence using commonly available log suites. This presentation builds on our previous publication that describes the unconventional reservoir petrophysical model we have developed (Holmes, 2014). Essentially, we define four porosity components, namely total organic carbon, clay porosity, effective porosity, and “free shale porosity.” This last component is an indirect calculation if the first three components do not sum to total porosity.  Porosity/resistivity plots can be constructed for the total porosity and interpreted in a standard fashion. These will mostly indicate a water-wet system where the effective porosity fraction is examined. A second porosity/resistivity plot compares resistivity with “free shale porosity,” and is clearly interpreted to indicate Archie saturation exponents of much larger than 2 — frequently in excess of 3 — indicating the oil-wet fraction of the reservoir system. Additionally, the plots suggest low to very low values of cementation exponent, ranging from 1.0 to 1.5.   Examples from the Bakken of Montana and North Dakota, the Niobrara of Colorado, and the Wolfcamp and Spraberry of Texas are presented showing quantitative distinction of water-wet vs. oil-wet reservoir components.