YIELDING, G., FREEMAN, B. & NEEDHAM, T. 1997.

Quantitative Fault Seal Prediction.

AAPG Bull. V.81, No.6, 897-917.

Abstract

Fault seal can arise from reservoir/non-reservoir juxtaposition or by development of fault rock of high entry-pressure.  The methodology for evaluating these possibilities uses detailed seismic mapping and well analysis.

A 'first-order' seal analysis involves identifying reservoir juxtaposition areas over the fault surface, using the mapped horizons and a refined reservoir stratigraphy defined by isochores at the fault surface.
The 'second-order' phase of the analysis assesses whether the sand-sand contacts are likely to support a pressure difference.

We define two types of lithology-dependent attributes: 'Gouge Ratio' and 'Smear Factor'. Gouge Ratio is an estimate of the proportion of fine-grained material entrained into the fault gouge from the wall rocks. Smear Factor methods (including 'Clay Smear Potential' and 'Shale Smear Factor') estimate the profile thickness of a shale drawn along the fault zone during faulting.  All of these parameters vary over the fault surface implying that faults cannot simply be designated 'sealing' or 'non-sealing'.

An important step in using these parameters is to calibrate them in areas where across-fault pressure differences are explicitly known from wells on both sides of a fault.  Our calibration for a number of datasets shows remarkably consistent results despite their diverse settings (e.g.  Brent Province, Niger Delta, Columbus Basin).  For example, a Shale Gouge Ratio of about 20% (volume of shale in the slipped interval) is a typical threshold between minimal across-fault pressure difference and significant seal.