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.
We present the first comprehensive experimental evaluation of CO2 EOR in organic rich shale. Experiments in preserved core demonstrated the potential of CO2 to extract the naturally occurring oil in organic rich shale reservoirs, whereas tests in re-saturated core plugs were used to compute accurate recovery factors, and evaluate the effect of soak time, operating pressure, and the relevance of slim-tube MMP on recovery. 18 core-flooding experiments were conducted in sidewall cores from different shale plays.
The cores re-saturated with crude oil, were first cleaned by Dean-Stark extraction, and submitted to porosity and compressibility determination. The re-saturation, confirmed by CT-scanning, was attained by aging the core plugs at high pressure for two to four months. In all experiments, glass beads surrounding core samples were used to simulate the proppant and physically recreate in the laboratory a hydraulic fracture connected to the shale matrix. The slim-tube MMP was measured with CO2, and core-flooding experiments were performed below, close to, and above the MMP. The displacement equipment was coupled to a medical CT-scanner that enabled us to track the changes in composition and saturation taking place within the shale cores during the experiments. Continuous CO2 injection and huff-and-puff were evaluated using soak time from zero to 22 hours. Fixed reservoir temperature was used in all the experiments.
Recovery factors ranged from 1.7 to 40%. The wide variation was the result of different experimental conditions for pressure and soak time. Both operational parameters were found to significantly affect the recovery. Increasing soak time at constant pressure consistently resulted in significant increase in recovery. The increase varied from 78 to 464% for different pressures and oil composition. Similarly, increasing operating pressure at constant soak time resulted in significant increase in recovery factor from 44 to 338% depending on soak time and oil composition. Unlike the typical response during CO2 EOR in conventional rocks, in organic rich shale, further pressure increases beyond the slim-tube MMP continued to increase the recovery factor significantly. In all runs, almost all oil recovery occurred within three days from the start of the experiment, and in all huff-and-puff tests the highest rate of recovery was observed in the first cycle, implying oil recovery with CO2 is a fast process, in comparison to oil re-saturation of the samples which occurs at a significantly slower rate.
This investigation demonstrates CO2 EOR is a technically feasible method to extract significant amounts of crude oil from organic rich shale reservoirs and it provides operational understanding of how to manage pressure and soak time to maximize recovery. The recovery factors obtained in this investigation, in the context of the vast reserves of crude oil contained in organic rich shale, can sustain a second shale revolution and further capitalize oilfield infrastructure.
Dang, Cuong (Computer Modelling Group Ltd.) | Nghiem, Long (Computer Modelling Group Ltd.) | Nguyen, Ngoc (University of Calgary) | Yang, Chaodong (Computer Modelling Group Ltd.) | Mirzabozorg, Arash (Computer Modelling Group Ltd.) | Li, Heng (Computer Modelling Group Ltd.) | Chen, Zhangxin (University of Calgary)
Many attempts have been made to understand, design, and optimize a chemical flooding process; however, the current low oil price environment makes its implementation very challenging from an economics point of view. Recently, CoSolvent Assisted Chemical Flooding (CACF) has been considered as a promising approach to reduce the cost of surfactant-based recovery methods, especially in heavy oil reservoirs. More importantly, recent studies indicated that CACF can be efficiently applied at relatively low temperature, i.e., without the need of steam injection. This helps reduce for the cost of steam generation and injection, and the associated greenhouse gas effects. This paper presents a new development in modeling CACF using an Equation-of-State (EOS) compositional reservoir simulator.
We used a new approach to model the behavior of the oil-water-microemulsion system based on solubility data without modeling type III microemulsion explicitly. The results showed an excellent agreement with numerous chemical coreflooding data and are in agreement with a chemical floodingresearch simulator. The new development presented includes the effects of cosolvent on rheological properties and phase behavior of microemulsion in the CACF process, particularly microemulsion viscosity and interfacial tension.
The proposed model showed good agreement with four published CACF coreflood experiments in which surfactant was not used in alkali and polymer chemical slugs. This model efficiently captures the complex chemical reactionsoccurring in the CACF process, i.e., generation of in-situ soap based on reactions between alkali and a rich acid component in heavy crude oil. The model provides consistent results with laboratory coreflood data at different operating temperatures, which is very important for heavy oil reservoirs. The ultimate recovery factor by CACF coreflooding is about 97%, similar to ASP (Alkali, Surfactant and Polymer) coreflooding, but without the need of surfactant injection.
Thermal and solvent-based EOR methods are not applicable in many of thin post-CHOPS heavy oil reservoirs in Western Canada. Alkaline-surfactant flooding has been suggested as an alternative to develop these reservoirs. The main mechanism behind these processes has been attributed to emulsion-assisted conformance control due to the effect of synthetic and/or natural surfactants. Because nanoparticles (NPs) offer some advantages in emulsion stabilization, here we combine surface-modified silica NPs and anionic surfactants to enhance the efficiency of heavy oil chemical floods.
Based on the results of bulk fluid screening experiments, in the absence of surface-modified silica NP surfactant concentration should be tuned at the CMC (between 1 and 1.5 wt. %) to achieve the highest amount of emulsion. These emulsions are much less viscous than the originating heavy oil. However, at surfactant concentrations far from the CMC, complete phase separation occurs 24 hours after preparation. In the presence of surface-modified silica NP this emulsification was achieved at much lower surfactant concentration. The mixture of 0.1 wt. % anionic surfactant and 2 wt. % surface-modified silica NP produce a homogeneous emulsion of heavy oil in an aqueous phase. This observation was not observed when aqueous phase contains only either 0.1 wt. % anionic surfactant or 2 wt. % silica NP.
Preliminary tertiary chemical floods with water containing 0.1 wt. % surfactant and 2 wt. % surface-modified silica NP yielded an incremental oil recovery of 48 % OOIP, which is remarkably higher than that of either surfactant or NP floods with incremental recoveries of 16 and 36 % OOIP, respectively. Tertiary recovery efficiency, defined as ratio of incremental recovery factor to maximum pressure gradient during the tertiary flood, is six times greater for the surfactant/NP mixture than for the surfactant-only flood. This enhancement in recovery efficiency is of great interest for field applications where high EOR and large injectivity are desired.
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.
The improved oil recovery of unconventional shale reservoirs has attracted much interest in recent years. Gas injection, such as CO2 and natural gas, is one of the most considered techniques for its sweep efficiency and effectiveness in low permeability reservoirs. However, the uncertainties of fluid phase behavior in shale reservoirs pose a great challenge in evaluating the performance of gas injection operation. Shale reservoirs are featured with macro-scale to nano-scale pore size distribution in the porous space. In fractures and macropores, the fluid shows bulk behavior, but in nanopores the phase behavior is significantly altered by the confinement effect. The integrated behavior of reservoir fluids in this complex environment remains uncertain.
In this study, we investigate the nano-scale pore size distribution effect on the phase behavior of reservoir fluids in gas injection for shale reservoirs using a multi-scale equation of state modeling. A case of Anadarko Basin shale oil is used. The pore size distribution is discretized as a multi-scale system with pores of specific diameters. The phase equilibria of methane injection into the multi-scale system are calculated. The constant composition expansions are simulated for oil mixed with various fractions of injected gas. Bubble point, swelling factor, criticality and fluid volumetrics are studied in comparison to the behavior of the bulk fluid. It is found that fluid in nanopores becomes supercritical with injected gas, but lowering the pressure below bubble point will turn it into the subcritical state. The swelling factor is slightly higher with nanopores, and bubble point is lower than the bulk. The degree of deviation depends on the amount of injected gas.
The current in situ exploitation of oil sands in Alberta employs steam-based recovery methods, which are energy-intensive. A few companies are adding solvent to steam aiming to reduce steam requirements. The mechanism of oil recovery by steam with added solvent is not clear. Over the years, on several occasions- as at the present time- the oil industry has resorted to the use of solvents with steam in thermal recovery operations. The past trials with solvent were short-lived in view of the cost of solvents as well as the lack of success. Given the controversy regarding the use of solvents with steam, this work is intended to explain whether solvent injection with steam increases oil recovery or not.
In this work, a new analytical model is developed for describing the solvent-SAGD performance based on the combination of an overall solvent mass balance, heat balance and volumetric oil displacement and Darcy's oil rate using a mixture viscosity model as a function of temperature and solvent concentration ahead of front which satisfy the equilibrium in the system.
The objectives of this work are to predict: vapour-steam chamber growth, oil production rate, solvent production rate, solvent loss (or solvent retention) rate, and the effect of solvent type and concentration on the solvent-SAGD process. The results show that the rate of solvent retention increases over time, while the production rates of solvent and bitumen decrease.
The efficiency of this process is evaluated using Cumulative Steam-Oil Ratio (CSOR) and cumulative solvent-oil ratio, which permits a comparison of the efficiency of SAGD and solvent-SAGD processes for different solvents. On the whole, the results of this approach give a better understanding of the mechanism of oil production during the solvent-SAGD process by interconnecting vapour chamber conditions and the conditions of heated and diluted oil ahead of the interface.
While CO2 flooding is expected to increase oil recovery, deviations of actual production from predicted values add significant challenges when optimizing flood design under uncertain conditions. The aim of this paper is to introduce a comprehensive optimization process with uncertainty analysis to obtain a more plausible decision for a field application scenario. In this paper, a comprehensive optimization process is developed to optimize the production performance of entire production lifespan for a CO2-WAG EOR process in Pubei reservoir, Turpan-Hami Basin. Start times of the waterflooding and CO2 WAG proess (i.e., durations of the primary production and waterflooding) are also included in the optimization process as well as the producer’s bottomhole pressures and injection rates, in addition to the water and gas injection rates for the WAG process, WAG ratio, and well bottomhole pressures at the producers. The comparison is then performed between the conventional WAG optimization processes with the comprehensive optimization process. A total of 80 reservoir realizations is generated and history-matched to consider the impacts of the geological uncertainty on the optimization process. Finally, the reliability of this optimization design is quantified under the geological uncertainty. Results from a deterministic comprehensive optimization design demonstrate that the oil recovery and NPV of the optimized CO2-WAG process are increased by 23.4% and 51.3%, respectively, in comparison to the optimal case obtained by the conventional WAG optimization process. After incorporating uncertainties into the geological model, the distributions of oil recovery and NPV, including P10, P50, P90 are quantified. Based on uncertainty assessment, it is found that the optimized CO2-WAG scheme is a reliable scheme for the reservoir development. This paper provides quantitative insights on the significance of both geological and operational factors on the reliability of optimal design over the entire life span of a CO2 WAG operation. It is expected that the integrated workflow will help operators to optimize well performance more efficiently and predict production performances with higher reliability.
By coupling heat and mass transfer for C3H8–
Solvent Aided-Steam Flooding (SA-SF) focuses on maximizing the oil production by reducing the economic and environmental challenges created by steam generation. However, the solvent selection is vital due to the interaction of solvents with asphaltenes. Moreover, the polar nature of asphaltenes also enables asphaltene-steam interaction which may result in emulsion formation. This study investigates solvent-asphaltene-steam interaction during SA-SF with low and high molecular weight asphaltene insoluble solvents.
Two different solvents were tested; n-hexane (E1 and E4) and a commercial solvent (CS) (E2 and E5) with four flooding experiments; two miscible flooding (E1 and E2) and two SA-SF (E4 and E5) experiments. Results were compared with steam flooding (E3) experiment. The performance evaluation of different enhanced oil recovery methods was accomplished by comparing the oil recovery rates. The asphaltene content of produced oil samples was determined by standard methods. The asphaltene-steam interaction was analyzed with microscopic images, and the water content of produced oil samples was measured by Thermogravimetric Analysis (TGA).
Even though similar cumulative oil productions were obtained by the end of E1 (n-hexane-flooding) and E2 (CS-flooding), the produced oil quality varied due to asphaltene and clay contents. While higher clay content was measured for E1, E2 had a lower quality, due to higher asphaltene contents. This finding is due to the heavy dearomatized hydrocarbons composition of the CS which ranges from C11 up to C16 and enables more asphaltene production. Even though, E5 yielded the highest liquid production among all experiments; the produced liquid was composed of emulsified oil. The solvent aided-steam flooding (SA-SF) experimental results, which have been conducted with n-hexane/steam (E4) and CS/steam (E5) injections, suggest that as the asphaltene content increases in produced oil samples, more hard-to-break emulsions are formed. The unusual stability of these emulsions can be attributed to the nature of the asphaltene present in the produced oil.
From the results presented, it is recommended the use of lower carbon number solvents to leave the larger amounts of asphaltenes in the reservoirs. The solvents differed in their interactions with the asphaltenes present in the oil and with the steam that has a direct impact not only on the quantity of oil produced but the quality as well. Hence, the wise selection of the appropriate solvent cannot be ignored during solvent aided-steam flooding processes.