In this paper, we present for the first time, a classification system for naturally-occurring gas hydrate deposits existing in the permafrost and marine environment. This classification is relatively simple but highlights the salient features of a gas hydrate deposit which are important for their exploration and production such as location, porosity system, gas origin and migration path. We then show how this classification can be used to describe eight well-studied gas hydrate deposits in permafrost and marine environment. Potential implications of this classification are also discussed.
Introduction Of the three permafrost regions, our calculations show Mohe Basin has the thickest hydrate stability (1300 m). This is followed by Qinghai-Tibet Plateau (1200 m) and Qilian Mountain (800 m).
Yuan, Qingwang (University of Regina) | Wang, Shuoshi (University of Oklahoma) | Wang, Jinjie (China University of Geosciences) | Zeng, Fanhua (University of Regina) | Knorr, Kelvin D. (Saskatchewan Research Council) | Imran, Muhammad (Saskatchewan Research Council)
The frontal instabilities are a key control factor which can significantly affect the sweep efficiency and oil recovery in miscible flooding processes. Under unfavorable viscosity ratio between injection solvent and oil, the frontal instabilities are nearly unavoidable. However, how to suppress the instabilities, especially with low additional costs, should be carefully investigated. The present study examines the time-dependent displacement rates on flow instabilities in miscible flooding. Within the capacity of injection pumps, the injection rates are varied with time in a fast alternating manner. It is found that this kind of variable rates can stabilizing frontal instabilities by enhancing initial uniform mixing of solvent and oil. It therefore suppresses the later development of instabilities. Eventually, a much less unstable front is obtained when compared with the constant injection rate. Other parameters such as the amplitude of rates are also examined. The variations of propagation of front with time are analyzed for the change of rate strength. It is can therefore be concluded that this kind of time-dependent rate can improve oil recovery at very low additional rate within the capacity of pumps for the field EOR processes.
Gas hydrate has been found both in the permafrost and deep ocean in China. However, due to easier access, much lower well cost and proximity to existing gas pipelines, gas hydrate in the permafrost is more attractive for commercial development. In this paper we examine the published data on gas hydrate exploration in various Chinese permafrosts, identify the key technical challenges and suggest directions for future study.
Our study has identified Qilian Mountain Permafrost, Mohe Basin and Qinghai-Tibetan Plateau as the three permafrosts with highest potential for gas hydrate development. Of the three, only Qilian has confirmed occurrence of gas hydrate by coring. From the perspective of field operations, Qilian ranks highest in potential for development due to its proven hydrate occurrence, thickness of hydrate bearing layer and proximity to existing gas pipelines. Mohe ranks second due to its benign operating conditions. However, it lacks existing gas pipelines. Qinghai-Tibetan Plateau ranks third due to its high elevation which limits access and lack of oilfield infrastructure.
We found that the key subsurface uncertainty is the gas hydrate saturation. There is little information on it for all three permafrosts. Other subsurface uncertainties include the thickness of the permafrost, geothermal gradient beneath the permafrost, porosity, gas hydrate composition and permeability of the hydrate-bearing layer. Future research needs to determine these reservoir properties accurately.
Examination of core samples and logs from Qilian shows that gas hydrate distribution is discontinuous both vertically and areally. Therefore, a better way to quantify the uneven hydrate distribution in the reservoir is needed for reservoir engineering calculations.
Current estimates of well production rate by reservoir simulation are sub-commerical and probably due to the assumption of pure methane hydrate which limits the thickness of the gas hydrate stability zone. Also, the assumption of using horizontal wells for hydrate production may be optimistic due to shallow depths and the discontinuous nature of hydrate distribution. Consequently, new recovery methods besides depressurization and thermal stimulation will be needed to increase the well production rate.
Furthermore, we have identified a number of similarities in production engineering aspects of gas production from hydrate and coalbed methane (CBM) wells. Common challenges include reservoir depressurization by water production, solids production, need for artificial lift and difficulty in drilling long horizontal wells in shallow reservoirs. Therefore, some best practices from CBM production, such as pad drilling, artificial lift and water treatment methods, may be usable for gas hydrate production.
Yuan, Qingwang (University of Regina) | Zhan, Jie (University of Calgary) | Wang, Jinjie (China University of Geosciences) | Zeng, Fanhua (University of Regina) | Knorr, Kelvin D. (Saskatchewan Research Council) | Imran, Muhammad (Saskatchewan Research Council)
As an efficient enhanced oil recovery (EOR) technique, carbon dioxide (CO2) miscible flooding can greatly reduce the viscosity of oil and improve its mobility, and has great potential to achieve higher oil recovery. However, the disadvantage of CO2 flooding, when compared with waterflooding, is the relatively larger viscosity ratio between CO2 and oil. Under such unfavorable conditions, frontal instabilities, or viscous fingering, can easily develop. This may affect the performance of CO2 miscible flooding and result in less sweep efficiency and oil recovery.
In the present study, nonlinear numerical simulations were conducted to model the CO2 miscible flooding in subsurface porous media. Both concentration-dependent diffusion and a varying dispersion that is closely related with flow rates were incorporated into the mathematical model. The development of frontal instabilities with time was simulated with highly accurate numerical methods. More importantly, to reduce the unstable displacement and improve sweep efficiency, a time-dependent injection rate involving periodic alternation of injection and extraction was employed. Different from the widely used constant injection rate, this time-dependent displacement rate led to different flow dynamics and sweep efficiency, although the amount of CO2 injected was the same. In particular, the effect of a cycle period on the propagation of CO2 was carefully examined. It was found that a longer period led to earlier breakthrough of CO2 and less sweep efficiency. However, a shorter period with faster alternation of injection and extraction had a stabilizing effect. In particular, a later breakthrough was achieved and higher sweep efficiency at breakthrough was obtained compared with that of a constant injection rate. This indicates that pulsed displacement through fast switching of injection and extraction has the potential to maximize oil recovery in CO2 miscible flooding.
Miscible flooding is proven as an economical EOR process and can be used for a variety of different reservoirs. In CO2 miscible flooding, one of the most promising EOR techniques, the CO2 can become miscible with the oil when the pressure is higher than the minimum miscibility pressure (MMP).
Yuan, Qingwang (University of Regina) | Wang, Jinjie (China University of Geosciences) | Yao, Shanshan (University of Regina) | Zeng, Fanhua (University of Regina) | Knorr, Kelvin D. (Saskatchewan Research Council) | Imran, Muhammad (Saskatchewan Research Council)
Solvent-based processes have great potential to enhance oil recovery. The injected solvent is able to significantly reduce the viscosity of the oil and improve its mobility. In displacement processes, the frontal instability happening at the interface between solvent and oil can increase their surface contact area, while it also leads to earlier breakthrough time and less sweep efficiency if such instabilities develop too severely. Especially at very large mobility contrasts, the less viscous injected solvent can easily bypass the highly viscous heavy oil. Most of the previous studies on simulations of frontal instability are restricted to a small range of mobility ratio. In the present study, we adopted a highly accurate numerical method to simulate the detailed development of solvent fingering at extremely large mobility ratios in fully miscible displacements. At certain conditions, the case with a maximum mobility ratio as large as 22026.5 could be successfully modeled. This allowed analysis of the flow dynamics and mass transfer at such a large mobility contrast in miscible displacement processes. The breakthrough time and sweep efficiency at breakthrough were also investigated at small and extremely large values of mobility ratio through numerical simulations. With an increase in mobility ratio, the breakthrough time decreased, first very rapidly and then slowly. The breakthrough time varied as a power relationship with the mobility ratio for various Peclet numbers. Similar relationships were found for the sweep efficiency versus mobility ratio. This approach would be helpful for the accurate prediction of breakthrough time and sweep efficiency in miscible displacement under extremely large mobility contrasts.