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Determination of petro-physical properties of coal bed methane (CBM) reservoirs is essential in evaluating a potential prospect for commercial exploitation. In particular, permeability of coal and relative permeability of coal to gas and water directly impacts the amount of hydrocarbons that can be ultimately recovered. Due to the complex and heterogeneous nature of coal seams, proper relative permeability relationships are needed to accurately describe the transport characteristics of coal for reservoir modeling and production forecasting. In this work, absolute and relative permeability of different coal samples were determined experimentally under steady-state flowing conditions. Multiphase flow tests were conducted using brine, helium and carbon dioxide as the flowing phases under different magnitudes of confining and pore pressures. Results indicate that effective stress (Confining pressure-average pore pressure) has a significant effect on both absolute and relative permeability of coal. With increases in effective stresses, the absolute permeability decreases. Effective permeability and relative permeability, as well as the cross over point and the width of the mobile two-phase region decrease as the effective stress increases. In addition, the

Polymers are commonly used in chemical EOR flooding to provide mobility control to the injected fluid slugs. Water-soluble polymer injection in porous media usually results in polymer entrapment in the subsurface formation from adsorption, mechanical trapping, and hydrodynamic retention. These different entrapment mechanisms lead to permeability reduction (Rk). The term resistance factor (RF) is used to measure the impact of permeability reduction and viscosity enhancement from the polymer. The residual resistance factor (RRF) represents the residual permeability reduction to chase fluids (usually water) following a polymer flood. These phenomena are more prevalent in high molecular weight polymers. The effects of RRF are also sometimes evident when polymer injection is suspended (e.g., operational issues) and other fluids are injected in the formation instead. Post-polymer chase water injection is considered a viable option to improve economics of a polymer flood. Current models validate this optionality because they overestimate the efficiency of the chase water flood. Lab and field observations indicate that chase water after chemical flood can cause rapid breakthrough, and therefore it is generally not recommended. The shortfall lies in the assumption that permeability reduction during polymer flood is an irreversible mechanism and therefore the existing simulation models assume that the permeability reduction during and post-polymer flood is the same. In this work, we show that the permeability reduction mechanism can be somewhat reversible, and therefore the current models underestimate chase water injectivity, and more seriously can overestimate the efficiency of chase water displacement. For optimizing the slug size, over predicting chase water displacement efficiency has a critical impact on the project economics and it may wrongly indicate premature switching time from chemical to water injection. We provide an alternative permeability reduction model that does not assume irreversibility. The new model decouples permeability reduction during polymer flood from RRF during chase water flood. We validate the model using experimental data. Several test cases are provided to compare the two models and we finally demonstrate the applicability of the proposed model in an onshore polymer flood pilot. The new model also highlights the seriousness of the inefficiency of the post-polymer chase water injection.

Polymer flooding by liquid polymers is an attractive technology for rapid deployment in remote locations. Liquid polymers are typically oil external emulsions with included surfactant inversion packages to allow for rapid polymer hydration. During polymer injection, a small amount of oil is typically co-injected with the polymer. The accumulation of the emulsion oil near the wellbore during continuous polymer injection will reduce near wellbore permeability. The objective of this paper is to evaluate the long-term effect of liquid polymer use on polymer injectivity. We also present a method to remediate the near well damage induced by the emulsion oil using a remediation surfactant that selectively solubilizes and removes the near wellbore oil accumulation. We evaluated several liquid polymers using a combination of rheology measurement, filtration ratio testing and long-term injection coreflood experiments. The change in polymer injectivity was quantified in surrogate core after multiple pore volumes of liquid polymer injection. Promising polymers were further evaluated in both clean and oil-saturated cores. In addition, phase behavior experiments and corefloods were conducted to develop a surfactant solution to remediate the damage induced by oil accumulation. Permeability reduction due to long term liquid polymer injection was quantified in cores with varying permeabilities. The critical permeability where no damage was observed was identified for promising liquid polymers. A surfactant formulation tailored for one of the liquid polymers improved injectivity three- to five-fold and confirms our hypothesis of permeability reduction due to emulsion oil accumulation. Such information can be used to better select appropriate polymers for EOR in areas where powder polymer use may not be feasible.