'Faculty of Mining, Geology and Petroleum Engineering'
Abstract
Most reservoirs, such as carbonate reservoirs not only have structural heterogeneities (e.g. complexly shaped geobodies or fractures). But they also have distributed wettabilities and are mixed- to oil-wet. The interplay of structural and
wettability heterogeneities impacts sweep efficiency and oil recovery. Choosing
the appropriate Improved Oil Recovery (IOR) or Enhanced Oil Recovery (EOR) technique based on adequate predictions of oil recovery requires a sound understanding
of the fundamental controls on fluid flow in mixed- to oil-wet andstructurally complex rocks. The underlying multiphase flow processes are modelled with physically robust flow functions, i.e. relative permeability and capillary pressure functions. Obtaining these flow functions is a challenging task, especially when three fluid phases coexist, such as during Water-Alternating-Gas (WAG) injection. In this work we use pore-network modelling, a reliable and physically based simulation tool, to predict three-phase flow functions. We have developed a new three-phase flow pore-network model for rocks with arbitrary
wettability, which allows us to analyse the fundamental multi-phase displacement
processes. Unlike other models, our model combines three main features:
(I) A novel thermodynamic criterion for formation and collapse of oil layers that
strongly depends on the fluid spreading behaviour and the rock wettability. The
model hence captures film/layer flow of oil accurately, which impacts, in particular,
the oil relative permeability at low oil saturation and hence the accurate prediction
of residual oil. (II) Multiple displacement chains, where injection of one
phase at the inlet triggers a chain of interface displacements throughout the network. This allows accurate modelling of the mobilization of disconnected phase
clusters that arise during higher order (WAG) floods. (III) The model takes as
input realistic 3D pore-networks extracted from pore-space reconstruction methods
and Computed Tomography (CT) images, preserving both topology and pore
shape of the rock. The model comprises a constrained set of parameters that can
be tuned to mimic the wetting state of a given reservoir. We have validated
our model against available experimental data for a range of wettabilities. We
demonstrate the importance of film and layer flow for the continuity of the various
phases during subsequent WAG cycles and for the residual oil saturations.
A sensitivity analysis has been carried out with the full 3D model to predict
three-phase relative permeabilities and residual oil saturations for WAG cycles
under various wetting conditions with different flood end-points and for different
rock types. This revealed a wide range of three-phase relative permeabilities
and residual saturations. The pore-scale generated three-phase flow functions
have then been used in a heterogeneous reservoir model. Here we demonstrate
their impact on the sweep efficiency after gas injection and WAG for a range of
realistic wettability scenarios. We show that the uncertainty in flow functions
can be as big as the geological uncertainty in a reservoir model that was history
matched for an extended waterflood