Abstract:The technical feasibility of underground coal gasification (UCG) has been established through many field trials and laboratory-scale experiments over the past decades. However, the UCG is site specific and the commercialization of UCG is being hindered due to the lack of complete information for a specific site of operation. Since conducting UCG trials and data extraction are costly and difficult, modeling has been an important part of UCG study to predict the effect of various physical and operating parameters on the performance of the process. Over the years, various models have been developed in order to improve the understanding of the UCG process. This article reviews the approaches, key concepts, assumptions, and limitations of various forward gasification UCG models for cavity growth and product gas recovery. However, emphasis is given to the most important models, such as packed bed models, the channel model, and the coal slab model. In addition, because of the integral part of the main models, various sub-models such as drying and pyrolysis are also included in this review. The aim of this study is to provide an overview of the various simulation methodologies and sub-models in order to enhance the understanding of the critical aspects of the UCG process.

CO2 injected with water often gives premature breakthrough and reduces its absorption during sequestration and oil recovery applications. Water-soluble polymers are used to increase CO2 absorption via an increase in water viscosity that restricts CO2 movement and thus its early release. The efficacy of polymer CO2 absorption methods can be further increased in the presence of nanoparticles (NPs) that interact with polymer chains and create a steric barrier to improve CO2 absorption. Thus, nanofluids prepared with compatible NPs might be a safe and reliable method to improve CO2 absorption of polymer methods. In this work, a nanofluid prepared with silica NPs (0.1–1.0 wt %) in base fluid of oilfield polymer [(polyacrylamide (PAM) with typical oilfield concentration (1000 ppm)] was tested for CO2 absorption and compared with the one of PAM fluid at different temperatures (303 and 353 K). The inclusion of SiO2 in PAM fluid provided stable nanofluids that exhibited good dispersion stability without NP settlement for days. Thus, the efficacy of PAM fluid CO2 absorption significantly increased with nanofluids as reported through microscopic, kinetics, and molality results. The increase in NP concentration and temperature (353 K) showed an inverse relationship with CO2 absorption in nanofluids, mainly due to enhanced NP aggregation; thus, the use of nanofluids for CO2 absorption is critical at high temperature and high NP concentration. The NP effect on CO2 stabilization and absorption is finally supported through UV–vis measurements. The study highlighted important aspects of CO2 absorption and is a forward step toward the use of nanofluid together with the considerable possibility of enhanced CO2 miscible oil recovery.

Summary Since the late 1960s, several enhanced–oil–recovery (EOR) researchers have developed various continuum and pore–scale viscoelastic models for quantifying the altered injectivity and incremental oil recovery because of the polymer's viscoelastic effects. In this paper, limitations in each of the continuum and pore–scale models are discussed. The critiques are made on the basis of the contradicting literature. Most of the earlier models rely on the exclusive use of the Deborah number to quantify the viscoelastic effects. The Deborah number overlooks mechanical–degradation effects. There exists a large difference in the magnitudes of the reported Deborah number in the literature because of the inconsistency in using different relaxation time and residential time. Oscillatory relaxation time used by most of the EOR researchers to calculate the Deborah number failed to distinguish the different porous–media behavior of the viscous and viscoelastic polymer. Therefore, the accuracy of relaxation time obtained from the weak oscillatory field for EOR applications in porous media is questionable. The main limitation with all the existing continuum viscoelastic models is the empirical reliance on coreflood data to predict the shear–thickening effects in porous media. The strain hardening index, needed for quantifying the thickening regime, cannot be obtained by the conventional shear rheological techniques. The conventional capillary number (Nc) failed to explain the reduction in residual oil saturation (Sor) during viscoelastic polymer flooding. Pore–scale viscoelastic models use the conventional oscillatory Deborah number for quantifying the polymer's viscoelastic effects on Sor reduction. However, this approach has many drawbacks. Discussions on the shortcomings of the existing viscoelastic models caution the current chemical EOR (cEOR) researchers about their applications and potential consequences. Also, this research provides a path forward for future research to address the limitations associated with the quantification of viscoelastic flow through porous media.

Experiments were performed to study the diffusion process between matrix and fracture while there is flow in fracture. 2-inch diameter and 6-inch length Berea sandstone and Indiana limestone samples were cut cylindrically. An artificial fracture spanning between injection and production ends was created and the sample was coated with heat-shrinkable teflon tube. A miscible solvent (heptane) was injected from one end of the core saturated with oil at a constant rate. The effects of (a) oil type (mineral oil and kerosene), (b) injection rates, (c) orientation of the core, (d) matrix wettability, (e) core type (a sandstone and a limestone), and (f) amount of water in matrix on the oil recovery performance were examined. The process efficiency in terms of the time required for the recovery as well as the amount of solvent injected was also investigated. It is expected that the experimental results will be useful in deriving the matrix-fracture transfer function by diffusion that is controlled by the flow rate, matrix and fluid properties.

It has been long believed that the viscoelasticity of polymer solution improves the displacement efficiency in polymer flood operations, but the individual effect of elasticity has not been distilled for a single viscoelastic polymer. In this study, the effect of elasticity of polymer-based fluids on the sweep efficiency is investigated by injecting two polymer solutions with similar shear viscosity but significantly different elastic characteristics. Blends of various grades of polyethylene oxide (PEO) with similar average molecular weight and different molecular weight distribution (MWD) were prepared by dissolving in deionized water. The polymer solutions exhibited identical shear viscosity but different elasticity. A series of experiments were performed by injecting the polymer solutions in a special core holder designed to simulate radial flow through a sandpack, which was saturated with mineral oil. Injection was done through a perforated injection line located at the center of the cell and fluids were produced through two production lines located at the periphery. The experiments were conducted within a shear rate range of field applications. Since both polymer solutions had similar viscosity behavior but different elastic properties, it was possible to see the effect of elasticity on the displacement efficiency alone. Results of the polymer flooding experiments indicated that the sweep efficiency of a polymeric fluid could be effectively improved by adjusting the MWD of polymer solution at constant shear viscosity and concentration of the polymer. The polymer solution with higher elasticity exhibited considerably higher resistance to flow through porous media than the solution with lower elasticity resulting into higher displacement efficiency and lower residual oil saturation.