- journal_title：AAPG Bulletin
- Contributor：Graham Yielding ; Brett Freeman ; D. Tim Needham
- Publisher：American Association of Petroleum Geologists (AAPG)
- Date：1997-
- Format：text/html
- Language：en
- journal_abbrev：AAPG Bulletin
- issn：0149-1423
- volume：81
- issue：6
- firstpage：897
- section：Articles
Fault seal can arise from reservoir/nonreservoir juxtaposition or by development of fault rock having 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 by 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 nonsealing. 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 data sets 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.