Combination of complex sedimentation environment and carbonates’ diagenetic alterations render carbonate reservoirs to be very heterogeneous and often naturally fractured. Heavy oil trapped in carbonate reservoirs worldwide is estimated to be over 255 billion cubic meters. The drastic differences in flow and storage capacity of the fracture and matrix networks trigger the need for larger volumes of steam to be injected to produce one cubic meter of heavy oil production, making the application of thermal recovery processes in these reservoirs to be more economically challenging and highly energy intensive.
Recovery of heavy oil from naturally fractured reservoirs is weakly controlled by viscous forces and mostly controlled by capillary and gravity forces, in addition to convection and conduction heat transfer. This makes proper representation of fracture and matrix characteristics to be of paramount importance to the reliability of modeling thermal recovery processes.
This paper discusses the effect of variable fracture characteristics including fracture typing, spacing, and apertures on the performance of dual permeability models under different thermal recovery processes. Further, the paper demonstrates the necessity to characterize partially mineralized fractures and shows its effect on thermal conductivity from fractures to matrix blocks.
The effect of wettability on the recovery process is also discussed. Oil recovery in fractured reservoirs is highly influenced by imbibition process which is most effective under strong water wetness. The paper addresses the performance under water, oil and mixed wettability conditions. Furthermore, the paper shows that proper representation of capillary pressure hysteresis could cause considerable change in oil recovery performance. The modeling work in this paper helps to curtail any extra optimism that may originate from wrongly characterized dual permeability models. Finally, and in case reservoir characteristics are not well determined then forecasting based on uncertainties of reservoir characteristics should give operators a way to estimate the risk involved in the exploitation process of the carbonate resources.
Relative permeability profile is one of the most uncertain parameters and challenging requirements in field performance models. It is a mandatory element for multi-phase flow calculations and has a significant impact on development schemes, expected hydrocarbon recovery factor and the related revenues. Moreover, it impacts the surface facilities decision based on predicted produced fluids and recycling requirements, which might affect the economics of any related projects. Accordingly, obtaining representative relative permeability profile is a historical continuous challenge in the industry through common laboratory methods of steady state and unsteady state along with other numerical modeling approaches.
Experimental relative permeability profiles using both methods of steady state4 and unsteady state have been obtained for one of the main reservoir rock types (RRT A ) from a giant carbonate field in the Middle East. Comprehensive characterization and detailed numerical modeling for mixed wettability carbonates at full reservoir conditions has been studied covering all the details of rock properties, capillary pressure coupled with relative permeability profiles. The analysis revealed the uncertainty associated with each measurement method and surprisingly the limited data range of unsteady state method. Moreover, for the selected reservoir rock types, non-unique relative permeability profiles have been obtained using various experimental approaches and empirical correlations within the numerical modeling process in which different produced relative permeability profiles matched reasonably the laboratory reference measurements.
The resultant relative permeability profiles associated with uncertainty range presented in this paper has shown the significant influence of the measurement method selection, which impact the dynamic simulation models predictions and the eventually field development options. This work provides insight on the experimental methods selections and optimum conditions to acquire representative relative permeability profiles with emphasis on possible sources of uncertainties and errors. It clearly demonstrates the relative permeability accuracy levels of various numerical modeling processes and the potential of non-unique profiles which dictate the reservoir dynamics, performance as well as economics.