Rates of reservoir fluid mixing: implications for interpretation of fluid data

Abstract

This paper highlights the benefits of using knowledge of the rates of fluid mixing in the interpretation of reservoir fluid data. Comparison of the time it would take for a fluid difference to mix with the actual time available for mixing to occur allows two significant advances over a purely statistical analysis of reservoir fluid data: (1) differentiation of a step in fluid properties, indicative of a barrier to fluid communication, from a gradient indicative of incomplete mixing; and (2) quantitative estimation of the degree of compartmentalization that can readily be adapted into models for prediction of reservoir production performance.We review the existing equations that estimate the mixing times for three main types of variation in fluid properties (fluid contacts, fluid density and fluid chemistry). In addition, a new relationship for fluid pressure mixing is presented. In each case the relationships were validated by comparison with numerical simulation. The different fluid mixing processes were compared by applying the equations to a range of simple fluid scenarios in one simple reservoir description. This shows that mixing times for fluid mixing processes are diffusion > fluid density > fluid contacts > fluid pressure. For each scenario, the processes were analysed in terms of the volume of fluid that must move in order to bring the system to equilibrium and the drive for fluid mixing (pressure difference × permeability/viscosity). Perhaps surprisingly, there is an excellent linear relation between fluid mixing times (a) calculated from the mixing equations and (b) estimated from volume/drive. This indicates that fluid volumes and mixing drive are the main controls on fluid mixing times. This can be used to derive simple interpretation guidelines to estimate mixing rates even in the absence of quantitative modelling. A simple field case study demonstrates how this understanding of fluid mixing times can add value to the interpretation of reservoir fluid data.

Faults and fault properties in hydrocarbon flow models

“…The gas-water contact is the same across the fault, and evidence that the fault was a static seal at the onset of production was interpreted from different fluid compositions measured in samples acquired from wells drilled on each side the fault. Smalley et al (2004) calculate that lengthy times are required to equilibrate fluid compositions in the absence of pressure gradients, and conclude that such differences are not necessarily evidence of compartmentalization. For example, diffusion-driven geochemical equilibration over distances in the order of only 500 m are possible in the 40 Myr since oil emplacement in the Ross field (Smalley et al 2004).…”

“…(2004) calculate that lengthy times are required to equilibrate fluid compositions in the absence of pressure gradients, and conclude that such differences are not necessarily evidence of compartmentalization. For example, diffusion‐driven geochemical equilibration over distances in the order of only 500 m are possible in the 40 Myr since oil emplacement in the Ross field (Smalley et al. 2004).…”

Use of pore pressure data from the Norwegian Continental Shelf to characterize fluid-flow processes in geological timescales

“…Increase of fluid volume in a subsiding basin can be caused by thermal expansion of the pore fluid and/or by the expulsion of hydrocarbons from kerogen and migration of hydrocarbons into the rock unit (Osborne & Swarbrick 1997;O'Connor et al 2011). A slower process associated with osmosis has also been suggested (Swarbrick & Osborne 1998;Smalley et al 2004). Pore pressure will increase in a compacting unit if the permeability of the rock is not sufficient to allow a rate of fluid expulsion which matches the rate of compaction.…”

“…In the oil industry, it is common practice to use a static approach in reservoir modelling: an equilibrium situation is assumed, and segments with different pressures are interpreted to be delineated by tight barriers. Such a static approach is a simplification that is valid for time periods relevant to production from a field (,50 years) but it will not capture the dynamic nature of the aquifer on a longer timescale (Smalley et al 2004; Fig. 1.…”

“…2014). Over geological timescales, segment boundaries could be regarded as low-permeability restrictions rather than barriers (Smalley et al 2004). Smalley et al (2004) and Smalley & Muggeridge (2010) used analytical models to investigate the time taken for fluid pressure and fluid composition to equilibrate within a formation across a low-permeability boundary.…”