Abstract: Integration of Permeability Estimates from Logs, Welltests and Cores, Neuquen Basin, Argentina

Schiuma, Mario - Chauvco Resources; Michel Claverie* and Marco Sanguinetti - Schlumberger

We describe and compare permeability estimates recorded in a key well of the field from the techniques of nuclear magnetic resonance (NMR), Stoneley wave slowness, elemental petrophysical analysis, wireline and formation tests, and core measurements.

The Lotena sediments, located in the Neuquen basin of central Argentina, have a fluvio-deltaic origin of Calovian age. The sand bodies are channels, bars and crevasse splays. The reservoirs are under various degrees of depletion and generally require hydraulic fracturing. Anomalous hydrocarbon fluids distributions are common. The sands are feldspathic litharenites, with 20 to 25% of orthoclase and plagioclase, and 30 to 40% of lithic fragments composed of vitric tuffs, granites and metaquartzites. About 4% of illite matrix and 4% of calcite, dolomite, quartz overgrowth, siderite and pyrite cement fraction are described. The porosity varies from 14 to 18%. Large variations of permeability are observed within the sand bodies, from a few to 500 millidarcies. The permeability contrasts are caused by variations of grain size, irregular grain sorting and cementation patches. The permeability and free fluid volume are usually highest at the sand base, and diminish with the grain size towards the top of the sequences.

The NMR logs provide the pore size and permeability gradation corresponding to the fining-up grain size in the channel. NMR measurements on core plugs confirm the log readings, and indicate a free fluid T₂ threshold of 13 msec. Mercury porosimetry tests correlate well with the NMR T₂ distributions. A Stoneley wave permeability is calculated from the difference between S_e, the elastic Stoneley slowness in a non-permeable formation, and S, the measured Stoneley slowness. The Stoneley permeability requires a calibration to yield absolute values, but is a reliable fluid permeability index. We estimate an intrinsic permeability from the weight percentage of minerals in the formation rock, their respective permeability factor, and the porosity.

We compare permeability estimates as they are calculated from detailed analysis, but without normalization (Figure-1), and we correlate features of the channels sequences on borehole images and core. Wireline formation tests and a production well test provide additional calibration points for these log permeability estimates. There is a fairly good agreement in most sands between the values calculated with the various methods, with some discrepancies. The base of each sand tends to be more permeable than the upper part, as expected from the coarser grain at the base of the channel sands. The core permeabilities are higher than logs and tests estimates, and we doubt that they are representative of the in-situ permeability. A simplified mineral-permeability model over-estimates the permeabilities in one layer, where the petrophysical results may not account for the matrix and cement minerals and texture.

AAPG Search and Discovery Article #90933©1998 ABGP/AAPG International Conference and Exhibition, Rio de Janeiro, Brazil