The in-situ steam based technology is still the main exploitation method for bitumen and heavy oil resources all over the world. But most of the steam-based processes (e.g., cyclic steam stimulation, steam drive and steam assisted gravity drainage) in heavy oilfields have entered into anexhaustion stage. Considering the long-lasting steam-rock interaction, how to further enhance the heavy oil recovery in the post-steam injection era is currently challenging the EOR (enhanced oil recovery) techniques. In this paper, we present a comprehensive review of the EOR processes in the post steam injection era both in experimental and field cases. Specifically, the paper presents an overview on the recovery mechanisms and field performance of thermal EOR processes by reservoir lithology (sandstone and carbonate formations) and offshore versus onshore oilfields. Typical processes include thein-situ combustion process, the thermal/-solvent process, the thermal-NCG (non-condensable gas, e.g., N2, flue gas and air) process, and the thermal-chemical (e.g., polymer, surfactant, gel and foam) process. Some new in-situ upgrading processes are also involved in this work. Furthermore, this review also presents the current operations and future trends on some heavy oil EOR projects in Canada, Venezuela, USA and China.
This review showsthat the offshore heavy oilfields will be the future exploitation focus. Moreover, currently several steam-based projects and thermal-NCG projects have been operated in Emeraude Field in Congo and Bohai Bay in China. A growing trend is also found for the in-situ combustion technique and solvent assisted process both in offshore and onshore heavy oil fields, such as the EOR projects in North America, North Sea, Bohai Bay and Xinjiang. The multicomponent thermal fluids injection process in offshore and the thermal-CO2and thermal-chemical (surfactant, foam) processes in onshore heavy oil reservoirs are some of the opportunities identified for the next decade based on preliminary evaluations and proposed or ongoing pilot projects. Furthermore, the new processes of in-situ catalytic upgrading (e.g., addition of catalyst, steam-nanoparticles), electromagnetic heating and electro-thermal dynamic stripping (ETDSP) and some improvement processes on a wellbore configuration (FCD) have also gained more and more attention. In addition, there are some newly proposed recovery techniques that are still limitedto the laboratory scale with needs for further investigations. In such a time of low oil prices, cost optimization will be the top concerns of all the oil companies in the world. This critical review will help to identify the next challenges and opportunities in the EOR potential of bitumen and heavy oil production in the post steam injection era.
Large scale polymer flooding projects in heavy oil are now ongoing in several countries and numerous other projects are at the pilot or design stages. However, there is currently no guideline for the maximum acceptable oil viscosity, one of the important parameters in the screening of new projects. Standard screening criteria do not take the latest field results into account and more recent guidelines rely mostly on viscosity averages whereas they should focus on the extreme values instead.
Since the laboratory can only provide little help to settle this issue we propose to examine current field projects for guidance.
To the best of the author's knowledge, the Pelican Lake and the Seal polymer floods, both in Canada, are operating in the highest oil viscosity ranges; moreover, the data is public and can easily be accessed. We have therefore examined the performances of polymer injection in the highest ranges of oil viscosity in both fields to get an understanding of the limits. This involved first the identification of the highest oil viscosity patterns, then the estimation of the live oil viscosity during the polymer flood in these patterns and finally the performances of the polymer flood.
Viscosity measurements are notoriously difficult and not always very reliable in heavy oil and the evaluation of in-situ viscosity is even more difficult; therefore, we used ranges of viscosity rather than definite values. The observations from Pelican Lake and Seal seem in good agreement and suggest that polymer flood is still feasible and can provide an acceleration in production for live oil viscosities up to 10,000-12,000 cp. There is little experience beyond these values, but it appears that for higher ranges of viscosity polymer injection becomes much more difficult; in Seal polymer flood does not appear to be working satisfactorily in oil viscosities above 14,000 cp.
To the best of the author's knowledge, this is the first time that the issue of maximum oil viscosity is investigated in such a manner. Although these results are preliminary and would require further confirmation from other field cases, this paper will provide guidance to engineers screening heavy oil reservoirs for potential application of polymer flood.
Enhanced oil displacement in a reservoir is highly affected by wettability alterations in conjunction with the lowering of viscosities during steam assisted gravity drainage (SAGD) for bitumen extraction. The impartation of energy in the form of heat to the fluid by injecting steam triggers an alteration to a more water-wet state during SAGD. However, the presence of three distinct phases in the reservoir has implications for the effective modeling of the complex fluid dynamics. Dependency of the relative permeability endpoints on the temperature realized as a function of the introduction of steam is difficult to model. Optimization of any steam process requires simulation in order to adequately characterize years of flow and so a model that is capable of representing three phase flow is necessary. To obtain this a pseudo-two phase relative permeability is proposed that assumes fractional flow theory is valid and treats the experiments as a waterflood.
In this study, experimental recovery data for two SAGD experiments and one hot water flood are empirically matched by manipulating relative permeabilities. The analytical approach implemented allows for the representation of fluid flow in the reservoir by achieving a pseudo-two phase relative permeability that results in comparable performance to the experiments. Waterflooding techniques were utilized which allowed for the negation of the steam phase in the model and so two-phase flow was established.
The sensitivity of the relative permeability curves to temperature change results in the inability to formulate a generic three-phase curve and so the pseudo-two phase curve is valuable for the purpose of simulation. The methodology presented enables the formulation of a simplified relative permeability that is unique to each process used and in that specific location. The model that was established was validated and proven credible by the good match with the experimentally obtained values.
Aminzadeh, Behdad (Chevron Energy Technology Company) | Hoang, Viet (Chevron Energy Technology Company) | Inouye, Art (Chevron Energy Technology Company) | Izgec, Omer (Chevron Energy Technology Company) | Walker, Dustin (Chevron Energy Technology Company) | Chung, Doo (Chevron Energy Technology Company) | Nizamidin, Nabijan (Chevron Energy Technology Company) | Tang, Tom (Chevron Energy Technology Company) | Lolley, Chris (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Alkali flooding in heavy oil reservoirs is known to stabilize emulsion in-situ and improve the recovery beyond that of conventional waterflood under certain boundary and initial conditions. The overarching goal of this study is to develop a systematic approach to optimize this process and capture underlying recovery mechanisms. Therefore, we experimentally evaluated the performance of alkali flood as a function of emulsion type and viscosity. Phase behavior and viscosity of the microemulsion are modified by introducing seven different surfactants. Microscope imaging techniques are employed to measure the droplet size distribution for type I and II emulsions. Viscosities of generated emulsions are measured with a rotational rheometer at low temperatures and with an electromagnetic viscometer at reservoir conditions. Finally, corefloods are conducted at different conditions to evaluate the performance of displacement as a function of emulsion type and viscosity. Enhanced alkali floods showed an incremental recovery of 8 – 50% beyond that of waterflood. Formation of higher viscosity emulsion has a large contribution on the sweep efficiency and therefore improved oil recovery during alkali flood; however, other mechanisms (e.g. entrainment and entrapment) also have contribute to the incremental recovery. Results of our experiments indicated that the incremental recovery is a strong function of emulsion type, emulsion viscosity, and the droplet size distribution.