Fault seal potential is an essential step in determining the potential for fluid migration and assessing risks during hydrocarbon exploration. Multiple assessment tools have been developed and focus on (1) lithological juxtaposition, of permeable and impermeable stratigraphic units, and (2) fault rock sealing, assuming that clay material gets smeared along a fault zone. Most of these tools rely heavily on well log data, whether it is collected and analyzed in 1-D or 3-D settings.
Fault sealing assessments can be greatly improved and reduce exploration risk by using 3-D seismic data as it expands this analysis to a 3-D setting. Inverted rock properties data from seismic accounts for lithological variations across any fault system, changes in displacement and in fault geometry and shape, and fault interactions such as transfer zones. The work presented here incorporates traditional fault sealing methods and applies them on seismic inversion data from the Parihaka fault system in the Taranaki Basin, offshore New Zealand.
The Parihaka fault system is a normal fault system in the northern central part of the Taranaki Basin and consists of three main en-echelon faults that were mostly active during the Plio-Pliostocene. Figure 1 shows the relative location of those three main faults, trending north-south with transfer zones connecting them. Structural analyses of those faults reveals a maximum displacement seen at the center of each fault, with the displacement minimum occurring at each of the transfer zone locations. Significant growth is seen on most of the intervals studied with maximum growth occurring during the Late Pliocene-Early Pleistocene age.
Well data is available from the Arawa No. 1 well (figure 1) located on the upthrown side of Fault A as well as from five nearby vertical wells. A strong relationship between rock properties, facies from the well data and seismic impedances is essential for accurate modeling and inversion of rock properties. Figure 2 shows the variation of density as a function of P-impedance colored by volume of shale values (Vshale) for various wells. The plot shows two major trends, a shale trend (black) associated with higher volume of shale and a sand trend (yellow) corresponding to a low volume of shale. The shale trend tends to have a lower P-impedance and higher density corresponding to a more compacted, less porous rock. The facies definition used is derived from the mudlog reports of Arawa No. 1 well, closest well to our fault system, and is characterized by four siliciclastic lithology types (sand, shale or mudrock, interbedded rock and siltstone). The observed trends allow for a proper definition of those facies on the inverted seismic volumes (of porosity and gamma ray). Rock property volumes such as porosity, volume of shale and facies volumes are derived from impedance volumes and used to assess fault sealing potential.
Fault Seal Assessment
For both the upthrown and downthrown blocks, 3-D juxtaposition analysis uses facies derived from seismic inversion data mapped on each fault plane. The least permeable stratigraphic unit at each location, from either the upthrown or downthrown block, is then projected onto the fault for seal analysis, assuming sand units as being the most permeable, interbedded sandstone/siltstone/shale units as the next most permeable, and then siltstone and shale units as the least permeable (fault seals). Similarly, an assessment of the shale gouge ratio is carried out using the inverted volume of shale and derived for each fault based on its actual displacement. The workflow assumes that a sand to sand juxtaposition and a less than 20-percent SGR are needed for major migration pathways to be considered.
Figure 3a shows a 3-D visualization of the least permeable facies along Fault A. The upthrown stratigraphic units are then traced onto the fault to allow for proper understanding of facies variation. Most of those high permeable pathways are seen in M10 and M20, with an increase in thickness towards the northern end of the fault. M00 and M30 have a few sand-sand juxtapositions mainly seen on the northern end of the fault. Similarly, figure 3b shows the estimated SGR percentage on Fault A based on the available inversion data. SGR values of less than 20 percent are then colored in light blue and highlighted for each fault, outlined in black.
The highlighted areas, having low SGR, match the location of sand to sand juxtaposition. Similarly, those areas tend to be thicker on the northern end of Fault A. This is related to the lower amount of displacement at each fault tip, and the higher displacement towards the center of the fault. The juxtaposition method shows a much wider, more continuous, and longer surface area of highly permeable rock compared to the SGR method. In addition, as seen in both methods, the highly permeable areas tend to be mostly located at the edge of each fault. This observation matches the location of the transfer zone, as formation displacement can vary across those zones, and the existence of other faults can complicate the sealing analysis.
Assessment of fault seal potential using seismic inversion volumes is an innovative workflow that goes beyond the limitations in 1-D data and accounts for variations in fault properties across the fault system. Some parts of the fault can be great migration pathways, particularly around transfer zones which can play a major role in understanding the total petroleum system. This emphasizes the importance of 3-D seismic data in not only interpreting and defining the structural history of the basin, but also in understanding migration pathways and hydrocarbon trapping.
Data (3-D seismic, well logs, mud logs and core descriptions) used in this work was available through New Zealand Petroleum and Minerals, Ministry of Business, Innovation and Employment.