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Lloydminster area that straddles Alberta and Saskatchewan border contains vast amounts of heavy oil deposits in thin unconsolidated formations. Cold Heavy Oil Production with Sand (CHOPS) has been successfully implemented in these reservoirs. However, primary recovery is still low averaging below 10%. How to economically recover the large amount of remaining oil in place is a challenge. Therefore, an effective follow up recovery process is required.Steam injection technologies cannot be widely applied because most of the Lloydminster heavy oil reservoirs are thin and the heat losses to overburden and under burden make the process uneconomic. Alternative solvent methods are not commercial yet due to uncertain oil recovery rates and low solvent recovery. Hybrid application of the aforementioned two technologies using hot water together with solvents could be an economic post CHOPS recovery process. The wormholes created during the primary recovery can be used to contact large reservoir volumes with hot water and solvent. This paper contains the results of hot water and solvent oil recovery experiments conducted in preserved heavy oil cores. Experimental work consisted of three phases. Cores were immersed in hot water in the first phase to pre-heat the formation. Next, cores were exposed to heptane as hydrocarbon solvent. Finally, cores were immersed in hot water again to recover the oil as well as the solvent. The ultimate oil recoveries varied between 42% and 88% OOIP and, the asphaltene precipitation varied between 2.5 wt% and 11.7 wt%. Experiments were also carried out with a distillate from Husky's Lloydminster upgrader used for heavy oil transportation in the pipelines. Better results were obtained if the distillate was used instead of the pure hydrocarbon solvent.It was observed that oil recovery at the end of the initial hot water injection phase due to thermal expansion and viscosity reduction was negligible compared to the ultimate recovery. However, the first phase serves to condition the reservoir for better diffusion in the second phase when the solvent is injected. The final phase of hot water injection causes the water to strongly imbibe into the matrix enhancing the oil and the solvent recovery.
Lloydminster area that straddles Alberta and Saskatchewan border contains vast amounts of heavy oil deposits in thin unconsolidated formations. Cold Heavy Oil Production with Sand (CHOPS) has been successfully implemented in these reservoirs. However, primary recovery is still low averaging below 10%. How to economically recover the large amount of remaining oil in place is a challenge. Therefore, an effective follow up recovery process is required.Steam injection technologies cannot be widely applied because most of the Lloydminster heavy oil reservoirs are thin and the heat losses to overburden and under burden make the process uneconomic. Alternative solvent methods are not commercial yet due to uncertain oil recovery rates and low solvent recovery. Hybrid application of the aforementioned two technologies using hot water together with solvents could be an economic post CHOPS recovery process. The wormholes created during the primary recovery can be used to contact large reservoir volumes with hot water and solvent. This paper contains the results of hot water and solvent oil recovery experiments conducted in preserved heavy oil cores. Experimental work consisted of three phases. Cores were immersed in hot water in the first phase to pre-heat the formation. Next, cores were exposed to heptane as hydrocarbon solvent. Finally, cores were immersed in hot water again to recover the oil as well as the solvent. The ultimate oil recoveries varied between 42% and 88% OOIP and, the asphaltene precipitation varied between 2.5 wt% and 11.7 wt%. Experiments were also carried out with a distillate from Husky's Lloydminster upgrader used for heavy oil transportation in the pipelines. Better results were obtained if the distillate was used instead of the pure hydrocarbon solvent.It was observed that oil recovery at the end of the initial hot water injection phase due to thermal expansion and viscosity reduction was negligible compared to the ultimate recovery. However, the first phase serves to condition the reservoir for better diffusion in the second phase when the solvent is injected. The final phase of hot water injection causes the water to strongly imbibe into the matrix enhancing the oil and the solvent recovery.
Summary The presence of oxygen and carbon dioxide in the injection and production streams of any high-pressure-air-injection (HPAI) project or the high oxygen partial pressures associated with enriched-air-/oxygen-injection projects may create serious safety concerns such as the potential for explosion or corrosion. Compilation of field problems and reported solutions from such projects indicate that no insurmountable problems exist in the implementation of HPAI projects. Generally, the operators have implemented safe operations successfully when injecting at pressures as high as 6,000 psi. The long-term successes of the HPAI projects in the Williston basin, which were initiated in 1978 by Koch Industries and continue to be operated today by Continental Resources, have confirmed that HPAI is a viable and safe process for recovering light oils. A number of oilfield oxygen-injection projects have also been undertaken since the early 1980s, when Greenwich Oil operated the first oxygen-injection project at Forest Hills, Texas. In Canada during the 1980s, oxygen was injected by BP/AOSTRA at Marguerite Lake, by Dome Petroleum at Lindberg, by Husky Energy at Golden Lake, by Mobil Oil at Fosterton, and by Gulf Canada at Pelican. In the US, oxygen-injection pilots were operated by Arco in the Holt Sand Unit (HSU), Texas, and more recently by NiMin Energy at Pleito Creek, California. With increased oxygen partial pressure, there is a greater chance of safety or corrosion problems. In fact, the high oxygen content associated with the HSU project in west Texas caused a severe energy release that resulted in test termination. The reported data on this field are scarce, and the nature of the energy release has not been discussed in detail. This paper will first review the operational aspects of some key air-injection field tests. Then, some important details on the HSU oxygen-injection pilot test will be discussed as a case study. The reasons behind the energy release in the HSU project will be discussed by use of the surveillance data, as well as combustion-tube-test and numerical-modeling results. Finally, best practices for future operation of HPAI tests will be reviewed. This paper is intended to provide a better understanding of the safety aspects of air/oxygen handling and proper practices in such operations.
Summary Modeling of air-injection-based processes for enhanced oil recovery (EOR) is a challenging task, mostly due to the complexity of the chemical reactions taking place. Also, the applicability of currently available kinetic models is limited to the reservoir systems they were originally developed for. The objective of this study is to derive a general chemical reaction framework that could be used to develop a kinetic model for a variety of crude oils (i.e., light or heavy oils). The work is based on the modeling of high-pressure ramped temperature oxidation (HPRTO) experiments, and combustion tube (CT) tests, performed on two different oil systems: a volatile oil that is near critical at reservoir conditions (44 °API), and a bitumen sample (10 °API). The HPRTO test is a kinetic experiment that intends to mimic the flow conditions within the reservoir and allows the determination of kinetic parameters of the different reactions. On the other hand, the CT test is meant to provide quantitative information on the combustion performance that can be expected in the field. Therefore, a kinetic model was derived for each of the cases based on the history match of an HPRTO experiment. The resulting model was validated by history matching a CT test for each of the oils. An important feature of these experiments is that they were performed at representative reservoir pressure conditions. The modeling approach chosen is an extension of the methodology originally proposed by Belgrave et al. in 1993, which is arguably the most comprehensive kinetic model available in the air injection literature. However, their model was developed from experiments performed on Athabasca bitumen, and it fails to represent the high-pressure air injection process as it occurs in light oil reservoirs, which are typically encountered at higher pressure conditions. For example, Belgrave’s model is based on the deposition and combustion of semisolid residue commonly known as “coke,” which is rarely present during the combustion of light oils at high pressure. As in Belgrave’s model, this study also describes the original composition of the oil in terms of maltenes and asphaltenes. The main difference lies in the presence and importance of oxygen-induced cracking reactions, as well as the combustion of a liquid-vapor flammable hydrocarbon mixture that is generated by cracking and oxidation reactions, which take place in the gas phase. Also, a unique feature of these simulations is that, apart from history-matching traditional variables such as thermocouple temperatures, fluid recovery, and produced gas composition, they also capture changes in the physical properties of the produced oil, such as viscosity and density, as well as the amount of the residual phases in the post-test core. This enhancement to Belgrave’s reactions allows modeling the air injection process in cases where coke is not the main source of fuel, such as in high-pressure light oil reservoirs. This work changes a paradigm deeply rooted in the original in-situ combustion (ISC) theory, by deriving a general chemical reaction framework that is used to develop a kinetic model for two crude oils, which are at opposite ends of the density spectrum. This allows the consolidation of a new and comprehensive general theory for the description of the ISC process as applied to oil reservoirs. Moreover, as the pseudocomponents representing the fuel are not present in the original oil, the method is not limited to a fluid characterization in terms of maltenes and asphaltenes but could potentially be applied along with any type of characterization of the original oil.
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