A combination of rising oil demand and declining supply from the conventional sources is
drawing global attention to the vast heavy-oil resources. These are commonly developed with
steam-based processes which, in most cases, burn fossil fuel to generate the required steam.
However, tightening constraints on fuel, water, and the environment are some of the factors
currently fuelling the interests in enhancements to the traditional steaming operations. To mitigate
some of the steam-related issues, we introduce two new thermal recovery methods, namely: (i)
alternating-injection of steam and CO2 (SAC), and (ii) alternating-injection of steam and flue-gas
(SAF).
The primary objective of this research is to assess the technical and commercial feasibility of
these new processes. To achieve this objective, we employ a combination of analytic modelling,
numerical simulations and experimental studies, investigating the reservoir heat-transport aspects
of steam-based processes, asphaltene-induced formation impairment, as well as the key controls
on reservoir dynamics and project economics.
In this work, the concepts of first-contact condensation (FCC) and multiple-contact condensation
(MCC) have been introduced as additional mechanisms of heat-transport in steam-based
processes. Hence, the traditional conductive-convective heat equations have been extended.
Solutions of these equations indicate that laboratory and field observations are better rationalised,
hence eliminating the current practice of employing unrealistic effective permeability and thermal
diffusivity to explain these observations. We also provide conditions under which petroleum
reservoirs may be analysed as adiabatic systems, and establish the relative influence of reservoir
and operating parameters on reservoir heat-transport.
Considering the asphaltene-precipitation potentials of CO2 and flue-gas, new models have been
formulated for describing asphaltene-induced impairment of the permeability of porous media
which, in turn, have been analysed as either closed (non-flowing) or open (flowing) systems.
Application of the models to rationalise the experimental results from common porous media, which
include sandstone, carbonate and glass-bead, validates their robustness. As a further test on the
robustness of the proposed models, their main underlying assumptions have been validated with a
set of capillary-flow experiments, which approximate asphaltene deposition at pore scale.
As a case study for reservoir simulations, the Nigerian heavy-oil deposit has been examined.
The sensitivity of reservoir response to reservoir, geometric (number and design of wells) and
operating parameters has been quantified. From these results, a realistic set of dynamic-simulation
models has been constructed for the Nigerian deposit. Within the parameter-space explored, the
main subsurface uncertainties are reservoir geometry, permeability distribution as well as fluid and relative-permeability models. In addition, all the processes, namely steam-alone, SAC and SAF, are
vulnerable to geometric and operating parameters.
On the net effect of in-situ asphaltene removal, the alternating-injection processes would only
yield higher oil recovery than the steam-alone process if there is significant in-situ deasphalting
such that the oil-viscosity reduction effect overrides the permeability impairment effect. Otherwise,
the miscibility of these gases in the oil-phase is not sufficiently high to take advantage of the
reduction of crude viscosity by dilution.
Finally, within the range of parameters evaluated, the three processes are technically and
commercially feasible for the Nigerian deposit investigated. However, in terms of economics and
robustness against commercial risks, the order is SAC > steam-alone > SAF. The reservoir model,
oil price and costs are found to be the main determinants of project risks. Given the limitations of
this research and the uncertainties in the input data used for analyses, we complete the work by
outlining the scope for further studies.