Changes

The shale gouge ratio works on the assumption that the sealing capacity is related directly to the percentage of shale beds or clay material within the slipped interval.<ref name=Yieldingetal_1997 /> The shale gouge ratio is the proportion of the sealing lithology in the rock interval that has slipped past a given point on the fault ([[:file:M91Ch13FG90.JPG|Figure 12]]). To calculate the shale gouge ratio, the proportion of shale and clay in a window equivalent to the throw is measured.

The shale gouge ratio works on the assumption that the sealing capacity is related directly to the percentage of shale beds or clay material within the slipped interval.<ref name=Yieldingetal_1997 /> The shale gouge ratio is the proportion of the sealing lithology in the rock interval that has slipped past a given point on the fault ([[:file:M91Ch13FG90.JPG|Figure 12]]). To calculate the shale gouge ratio, the proportion of shale and clay in a window equivalent to the throw is measured.

The prediction of fault seal is based on the assumption that if there is enough shale in the section undergoing faulting, then sealing is likely. There is often a continuous shale gouge or shale smear along fault planes where there is sufficient mudstone material available to be incorporated.<ref name=Lindseyetal_1993 /> <ref name=Foxfordetal_1998 /> Nevertheless, a number of field studies show that fault zones can have a significant degree of complexity and variation in deformation style along their lengths.<ref name=Childesetal_1997 /> <ref name=Jamesetal_1997 /> For example, Foxford et al.<ref name=Foxfordetal_1998 /> examined good exposures of the Moab fault in Utah. They found that the structure and content of the fault zone was so variable that it was impossible to predict the nature of the fault zone over even a 10-m (33-ft) distance. Doughty<ref name=Doughty_ 2003 /> found that the clay smear along the Calabacillas fault in New Mexico showed numerous gaps particularly where minor faults within the fault zone complex cut out the shale smear associated with the major slip plane. The implication of these field studies is that fault seal can be predicted but is subject to chance factors affecting the reliability of the prediction. Because of this, any fault seal prediction should be calibrated against actual evidence that fault compartmentalization is present. Yielding et al.<ref name=Yieldingetal_1999 /> made a fault seal analysis for the Gullfaks field in the Norwegian North Sea. Areas of higher shale gouge ratios (>20%) were more likely to seal on the basis of pressure history and chemical tracer movement between wells.

The prediction of fault seal is based on the assumption that if there is enough shale in the section undergoing faulting, then sealing is likely. There is often a continuous shale gouge or shale smear along fault planes where there is sufficient mudstone material available to be incorporated.<ref name=Lindseyetal_1993 /> <ref name=Foxfordetal_1998 /> Nevertheless, a number of field studies show that fault zones can have a significant degree of complexity and variation in deformation style along their lengths.<ref name=Childesetal_1997 /> <ref name=Jamesetal_1997 /> For example, Foxford et al.<ref name=Foxfordetal_1998 /> examined good exposures of the Moab fault in Utah. They found that the structure and content of the fault zone was so variable that it was impossible to predict the nature of the fault zone over even a 10-m (33-ft) distance. Doughty<ref name=Doughty_2003 /> found that the clay smear along the Calabacillas fault in New Mexico showed numerous gaps particularly where minor faults within the fault zone complex cut out the shale smear associated with the major slip plane. The implication of these field studies is that fault seal can be predicted but is subject to chance factors affecting the reliability of the prediction. Because of this, any fault seal prediction should be calibrated against actual evidence that fault compartmentalization is present. Yielding et al.<ref name=Yieldingetal_1999 /> made a fault seal analysis for the Gullfaks field in the Norwegian North Sea. Areas of higher shale gouge ratios (>20%) were more likely to seal on the basis of pressure history and chemical tracer movement between wells.

Gibson<ref name=Gibson_1994 /> provided a case history for fault seal analysis from the Columbus Basin, offshore Trinidad. Oil and gas fields occur in upper Miocene to Pleistocene deltaic sandstones of the Columbus Basin, located offshore to the southeast of the island of Trinidad. Numerous small faults dissect these reservoirs, and fault seal appears to be a critical feature controlling the size of these petroleum pools. Allan diagrams show that juxtaposition sealing is insufficient to explain the fault control on fluid contacts.

Gibson<ref name=Gibson_1994 /> provided a case history for fault seal analysis from the Columbus Basin, offshore Trinidad. Oil and gas fields occur in upper Miocene to Pleistocene deltaic sandstones of the Columbus Basin, located offshore to the southeast of the island of Trinidad. Numerous small faults dissect these reservoirs, and fault seal appears to be a critical feature controlling the size of these petroleum pools. Allan diagrams show that juxtaposition sealing is insufficient to explain the fault control on fluid contacts.