TransGen



TransGen, initially released in 1999, was the first software package to calculate geologically meaningful transmissibility multipliers for faults in hydrocarbon reservoir flow simulation models, following our now industry-standard workflow first published in Manzocchi et al. (1999). In a couple of projects between 2002 and 2008, run in partnership with Badleys and supported by Petrobras, Shell, Statoil and Total, TransGen became an extremely flexible reservoir simulator pre-processor featuring, among other things, functionality for including in full-field simulation models the effects of sub-resolution fault zone structure (e.g. relay zones too small to be included explicitly in the grid), two-phase fault rock properties (fault rock capillary threshold pressure and water-saturation dependent oil and water relative permeability functions of fault rock) and uncertainty in juxtapositions arising from uncertain fault throws. A comprehensive review of TeansGen functionality was presented in the form of a full-field sensitivity study to oil production by Manzocchi et al. (2008).

TransGen was written in the Fault Analysis Group and marketed by Badleys. In 2008 significant parts of TransGen were ported to TrapTester, and commercial enquiries should be directed to Badleys. Example applications are discussed below.





The Basic TransGen workflow calculates fault transmissibility multipliers as a function of the cell and fault geometry and properties, using generalisations of the workflow of Manzocchi et al. (1999). In this approach, fault permeability is estimated as a function of fault surface proxy-properties such as Shale Gouge Ratio, and fault rock thickness is estimated as a function of permeability. The value of the workflow in reservoir management is now well established (e.g. Jolley et al. (2007).

  


TransGen fault surface property modelling is extremely flexible, and in the example below is used to predict pre-production two-phase fault rock properties. Fault permeability (a) as a function of Shale gouge Ratio, and fault rock capillary threshold pressure (b) as a function of fault rock permeability. The reservoir capillary pressure (c) is determined by the fluid densities and the height of the Free Water Level, and where it exceeds the fault rock threshold pressure the fault rock will be partially oil saturated, with an effective water saturation dependant on the capillary pressure and the shape of the fault rock drainage capillary pressure curve (d). The initial reservoir fault rock relative permeability with respect to water (e) and oil (f) are functions of the effective water saturation and the shape of the fault rock relative permeability curves. Once production starts, these will change due to changes in reservoir saturation and capillary pressure. Functions used to calculate these fault rock properties are after Manzocchi et al. (2002).

  


Input for Full field flow simulation including two-phase fault rock properties calculated in TransGen is shown below. The reservoir fence diagram is coloured for KRNUMX; the Eclipse keyword used to assign a relative permeability table for flow in a particular direction. In the TransGen two-phase workflow, directional pseudo-relative permeability function are calculated for cells upstream of faults as a function of the cell properties, the across-fault pressure difference or flow rate, and the modelled fault rock properties. See Manzocchi et al. (2002, 2008) for details.

  


The TransGen workflow for including sub-resolution fault zone structure in full-field flow simulation modelling uses a process called Geometrical Upscaling. In this example the locations of unbreached sub-seismic fault relay zones are determined stochastically (green panels), and high resolution mini-models of modelled geometry are used to calculate the transmissibility of up-fault and cross-fault flow paths introduced by the relay zone. These mini-models transmissibilities (which include effects of fault rock permeability) are redefined as neighbour and non-neighbour connection properties in the original simulation model, allowing the effects of high resolution fault zone structure to be included in the full-field simulation model without modifying the geometry of the initial simulation model. See Manzocchi et al. (2008) for details.

  


A process similar to geometrical upscaling is used to include the effects on cross-fault juxtapositions (and their associated transmissibilities) of uncertainty in the interpretation of fault throws contained in the simulation model (a). In this TransGen workflow, correlated random fields are used to condition the spatial structure of the uncertainty according to a pre-defined conceptual model. Models with small correlation lengths (b) on the uncertainty contain a more varied range of juxtapositions perhaps representative of abundant small-scale displacement partitioning. Models with longer correlation lengths (c) tend to have similar overall displacement gradients to the initial model, but different displacement, representative of more systematic interpretational uncertainties. The automated TransGen modelling workflows allow this type of uncertainty to be included in automated history-matching studies (e.g. Irving et al. 2014).

  



TransGen has twice featured on the cover of Petroleum Geoscience: