Methods for Fault Seal Prediction -a worked example from the Niger Delta

A common cause of compartmentalization in oil and gas fields is the presence of sealing faults. Fault seal can arise from reservoir/non- reservoir juxtaposition or by development of fault rock of high capillary threshold pressure. The methodology for evaluating these possibilities uses routinely available data in the form of detailed seismic mapping and well analysis.The first of a 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. A detailed 9:1110 model of the fault surface(s) must be defined in three dimensions to position horizon cut-offs correctly, and so show the relationship of the juxtaposition pattern to potential structural spill-points. The second phase of the analysis assesses whether areas of sand- sand contact are likely to trap the buoyancy pressure generated by a hydrocarbon column. This is dependent on the nature of the fault rocks formed in the fault zone, which in turn is a function of the lithologies of the fault sequence. For prediction of fault- zone seal behaviour in clay-rich sequences, there are two general types of fault-seal algorithms: i.Smear Factor methods estimate the profile thickness of clay or shale smears e.g. Shell's Clay Smear Potential. ii. Shale Gouge Ratio is an estimate of the proportion of fine-grained material entrained into the fault zone from the wall rocks. We discuss in detail an example from the Nun River Field showing how these algorithms can be calibrated against sub- surface pressure data in hydrocarbon traps. For example, a Shale Gouge Ratio (SGR) of c. 20% is a typical threshold between areas of leaking and sealing fault surface. Higher values of SGR tend to trap larger buoyancy pressures, i.e. larger hydrocarbon columns