Improving or Enhancing the oil recovery appears as a challenge for many porous fractured carbonate reservoirs as unfavourable conditions for matrix oil production are often encountered, such as a low permeability or a weak water wettability of the matrix medium. The selection, optimization and risk minimization of a production scenario for such fields goes through a clear understanding of the underlying physical mechanisms, together with a sufficient characterization of the fracture network and the evaluation of determinant matrix properties.
Considering the above context, this paper revisits the multiphase spontaneous displacement mechanisms taking place in matrix blocks during water drive production processes, in order to identify the limiting factors and parameters for oil recovery and to open promising research perspectives for Enhanced Oil Recovery (EOR).
Firstly, a simple analytical model of matrix-fracture water-oil transfers is presented and validated against published experimental results. This model takes into account the various contributions of co-current and counter-current flows depending on the magnitude of capillary forces and gravity forces. It also elucidates some upscaling issues from the laboratory core scale to the field scale.
Then, the mechanistic analytical approach of this paper is used as a framework for the assessment of enhanced oil recovery methods that are worth being considered to improve the production of oil-wet fractured carbonate reservoirs with a poor recovery prognosis. A parametric study is performed under the modified wettability and/or reduced interfacial tension (IFT) conditions that can be established through the injection of chemical agents in the water phase. Results indicate that designing a process to recover the matrix oil at an economic rate often turns out to be a real challenge for such reservoirs.
The paper concludes on recommendations for present field EOR assessment studies, and calls for further academic and applied research regarding the optimization of both pore-scale recovery and reservoir-scale recovery.
A significant proportion of world oil reserves, in the order of 20%, is generally assumed to lie in fractured reservoirs1. That proportion may fluctuate from one author to another because the classification of a reservoir as "fractured reservoir" is not straightforward as it depends on the classification criteria and also on the availability of reservoir information related to the presence of natural fractures. Regarding field exploitation, the determining criterion to consider a reservoir as fractured is not so much the presence of fractures but rather the impact of those fractures on the flow behaviour of the reservoir subjected to fluid extraction. Indeed, Nelson2 states that finding fractures is not enough because a fractured reservoir is before all "a reservoir in which naturally occurring fractures either have, or are predicted to have, a significant effect on reservoir fluid flow either in the form of increased reservoir permeability and/or porosity or increased permeability anisotropy".
A survey carried out by Allan and Sun3 over one hundred fractured reservoirs shows that the distribution of their ultimate oil recovery factor values covers a very large range, from 0 to 70%, with a frequency peak between 20 and 30%. They focused their study on Type II and Type III porous fractured reservoirs2, that are both characterized by a low matrix permeability. For Type III reservoirs with a high matrix porosity, all the well-fractured water-wet reservoirs have ultimate recovery factors ranging from 25% to 45%, while all the well-fractured oil-wet reservoirs have ultimate recovery factors ranging from 5 to 25%. Secondary waterflooding is also more efficient on water-wet reservoirs than on oil-wet reservoirs. The expected latter observation results from the predominant role played by natural drive mechanisms in the matrix oil recovery from wellfractured porous reservoirs.