Reservoir development is increasingly moving towards the heavy oil resources due to the rapid decline in conventional oil reserves. With the production of conventional low gravity crude oil being surpassed by heavy oil production in Alberta, the vast fields of heavy oil have been considered an emerging source of energy to the growing demands for oil and gas. Although the applications of thermal methods have been successful in many enhanced oil recovery (EOR) projects, they are usually uneconomic or impractical in deep and thin pay zones reservoirs. Therefore, polymer flooding is a preferred EOR technique in such reservoirs.An application of polymer flooding in heavy oil reservoirs dates back to more than half a century ago. However, it has long been considered a suitable method for reservoirs with viscosities up to 100 centipoises only. Recently, this EOR technique has attracted great attentions and become a promising method for oil recovery from heavy oil reservoirs with viscosities ranging from several hundreds to several thousands of centipoises. The main reasons for such a widespread application of the technique in heavy oil reservoirs during the last two decades have been rises in oil prices, extensive use of horizontal wells and advances in the polymer manufacturing technology. This paper aims to review the advances and technological trends of polymer flooding in heavy oil reservoirs since the 1960s. Upon the review, complete data sets of the laboratory works, pilot tests and field applications are established. The database provides qualitative description and quantitative statistics regarding both scientific research and practical applications. Then suitable ranges of some crucial affecting reservoir properties and polymer characteristics for successful field applications are examined. Finally, new screening criteria are developed specifically for heavy oil reservoirs based on an analysis of the data. The criteria are compared with the previously established ones. The outcome of this paper can be used as guidelines for screening, planning, design and eventually implementation of future projects.
Shale gas reservoirs have a high total organic content (TOC) and are composed of a lot of microspores, which result in a high content of adsorbed gas. Laboratory and theoretical calculations show that the adsorption potential of CO2 in shale is higher than that of CH4. In other words, the shales prefer adsorbing CO2 to CH4. Therefore, during CO2 injection, the adsorbed CH4 is released by CO2 adsorption, even in a high reservoir pressure. Several models have been studied to describe the pure and multicomponent adsorption on shale. The Langmuir and extended Langmuir models are usually applied in reservoir simulators, because other models are more complex and not applicable to be coupled into a simulator. In this work, a simulation study is carried out to investigate the effects of gas adsorption on primary recovery and CO2 enhanced recovery processes. Dual permeability, logarithmically spaced, locally refined grids are implemented to model natural and hydraulic fractures and to capture the sensitive changes of multicomponent adsorption. Reservoir pressure variation is coupled with a geomechanical module that updates porosity, permeability and fracture conductivity simultaneously at each time step. A multicomponent mixture on the basis of lab measured adsorption properties of the Eagle Ford shale are implemented into a reservoir simulator. Both primary recovery and CO2 huff-n-puff processes are investigated. The simulation results show multicomponent adsorption behaviors of extended Langmuir model can slightly increase the well performance in the primary recovery. However, the adsorption behavior is more complex during CO2 injection processes. This study highlights the effect of multicomponent adsorption on gas production during CO2 cycling, and provides an optimal enhanced recovery strategy for shale gas reservoir.
Over past decades, technology innovation in exploiting unconventional resources has become increasingly important. Associated with technologies applied in shale gas development, exploiting tight oil resources comes into a new stage. Primary recovery in tight oil reservoirs remains low even produced with massively hydraulically fractured horizontal wells. Waterflooding is applicable over a wide range of reservoir conditions but its recovery is not high enough. In addition, gas flooding suffers from channeling problems with existence of highly permeable channels. A water alternating gas (WAG) process seems a good method to recovery tight oil. Recent breakthrough in nanotechnology provides a promising technique in the oil and gas industry. Nanoparticles have a very high surface-volume ratio, easily moving into tight formation without external forces. Nanoparticles additive does not raise weight of an injection fluid, associated with wettability alteration and interfacial tension reduction, and can be an excellent solution in improving recovery in tight oil reservoirs. This paper demonstrates the merits of nanofluids; concentration of 0.05wt% nanofluid gives the best performance in a core flooding test. Simulations of nanoparticles additive in a WAG process are run by Eclipse and CMG in various cases. As the degree of wettability alteration and permeability reduction highly depends on concentration of nanoparticles underground, a tracer is applied in the simulations to confirm the locations of nanoparticels underground and its concentration, and it shows that nanoparticles mainly stay around injection wells and high permeable zones. Simulation results show that a nanofluid alternating gas (NAG) process has a great potential in improving WAG performance, and it performs better with existence of natural fractures.
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