Co-history Matching: A Way Forward for Estimating Representative Saturation Functions

Abstract

Core-scale experiments and analyses would often lead to estimation of saturation functions (relative permeability and capillary pressure). However, despite previous attempts on developing analytical and numerical methods, the estimated flow functions may not be representative of coreflood experiments when it comes to predicting similar experiments due to non-uniqueness issues of inverse problems. In this work, a novel approach was developed for estimation of relative permeability and capillary pressure simultaneously using the results of "multiple" corefloods together, which is called "co-history-matching". To examine this methodology, a synthetic (numerical) model was considered using core properties obtained from pore network model. The outcome was satisfactorily similar to original saturation functions. Also, two real coreflood experiments were performed where water at high and low rates were injected under reservoir conditions (live fluid systems) using a carbonate reservoir core. The results indicated that the profiles of oil recovery and differential pressure (dP) would be significantly affected by injection rate scenarios in non-water wet systems. The outcome of co-history-matching could indicate that, one set of relative permeability and capillary pressure curves can reproduce the experimental data for all corefloods.

An integrated evaluation of enhanced oil recovery and geochemical processes for carbonated water injection in carbonate rocks

“…In our history matching procedure, it has been attempted to honour both quantitative (hard constraints) and qualitative (soft constraints) results. Details of experimental procedure and results can be found in [ (Mahzari, et al, 2018) ].…”

“…To be able to capture these two processes, the two coreflood experiments are history matched together. This new approach of history matching multiple coreflood together is called co-history-matching (Mahzari, et al, 2018).…”

“…Although, in the early stages, the in-situ gas formed is mainly composed of methane and light hydrocarbon components, the gas phase would be enriched with CO2 over time . This behaviour would provide enhanced CO2 storage capacity for carbonated water injection, where injected CO2 would become trapped in the a high pressure gas (Mahzari, et al, 2018). On the other hand, it has been repeatedly observed that the in-situ formed gas phase would remain immobile for high gas saturations, which can lead to the in-situ swelling of hydrocarbon phases (Mahzari, et al, 2018).…”

“…This behaviour would provide enhanced CO2 storage capacity for carbonated water injection, where injected CO2 would become trapped in the a high pressure gas (Mahzari, et al, 2018). On the other hand, it has been repeatedly observed that the in-situ formed gas phase would remain immobile for high gas saturations, which can lead to the in-situ swelling of hydrocarbon phases (Mahzari, et al, 2018). Although there is much experimental evidence for this complex threephase flow process only a limited number of simulation and modelling studies have been performed ].…”

“…Therefore, changing the relative permeability for carbonated water injection may be inconsistent with the physical process. Notably, the interaction of oils with carbonated water would lead to creation of three-phase flow (Mahzari, et al, 2018), which brings in three-phase relative permeability functions and hysteresis effects ). Therefore, the numerical simulation of this complex process requires considerations of this physical phenomena.…”