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The AAPG/Datapages Combined Publications Database

AAPG Bulletin


Volume: 68 (1984)

Issue: 4. (April)

First Page: 502

Last Page: 502

Title: Estimation of Sediment Compaction Profiles Using Combination of Real-Time Drilling Response Modeling and Direct Porosity Measurements: ABSTRACT

Author(s): John D. MacPherson, E. Nigh, Alun Whittaker


The detection of overpressured formations at the wellsite has been limited in the past to empirical rate-of-penetration normalization equations (e.g., "d" exponent). These equations are limited to specific bit types and require much interpretation by well site geologists, particularly in wildcat areas.

A new, theoretically based method of evaluating overpressures handles several bit types independently (milltooth, insert, Stratapax, and diamond), and the output (drilling porosity) is calibrated to true formation porosity through the use of pulsed nuclear magnetic resonance techniques on drill cuttings.

Extended output from the method produces the following: online formation porosity curves, formation permeability, formation pressures (pore, overburden, fracture), bulk rock properties (e.g., Poisson's ratio, using a compressibility model that observes the change in porosity with incremental overburden pressure), and formation and bottom-hole temperatures. The method frees the geologist to interpret the output as the well is drilled. Several examples describe the interpretive significance of the output. For example, a pseudosonic log generated by the model shows excellent correlation with wire-line sonic measurements in consolidated formations; on certain wells the maximum value attained by the formation pore pressure is controlled by the overlying fracture gradient (hence, an on-line fracture gradient allows prediction of the maximum pore pressures likely to be encountered).

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Copyright 1997 American Association of Petroleum Geologists