Fault seal analysis: Methodology and case studies

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 [open quote]first-order[close quote] 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 [open quote]second-order[close quote] phase of the analysis assesses whether the sand-sand contacts are likely to support a pressure difference. We define two lithology-dependent attributes [open quote]Gouge Ratio[close quote] and [open quote]Smear Factor[close quote]. Gouge Ratio is an estimate of the proportion of fine-grained material entrained into the fault gouge from the wall rocks. Smear Factor methods estimate the profile thickness of a ductile shale drawn along the fault zone during faulting. Both of these parameters vary over the fault surface implying that faults cannot simply be designated [open quote]sealing[close quote] or [open quote]non-sealing[close quote]. 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. Brentmore » Province, Niger Delta, Columbus Basin). For example, a Shale Gouge Ratio of c. 20% (volume of shale in the slipped interval) is a typical threshold between minimal across-fault pressure difference and significant seal.« less