[1] This paper is intended to provide insight into the controlling mechanisms of karst genesis based on an advanced modeling approach covering the characteristic hydraulics in karst systems, the dissolution kinetics, and the associated temporal decrease in flow resistance. Karst water hydraulics is strongly governed by the interaction between a highly conductive low storage conduit network and a low-conductive high-storage rock matrix under variable boundary conditions. Only if this coupling of flow mechanisms is considered can an appropriate representation of other relevant processes be achieved, e.g., carbonate dissolution, transport of dissolved solids, and limited groundwater recharge. Here a parameter study performed with the numerical model Carbonate Aquifer Void Evolution (CAVE) is presented, which allows the simulation of the genesis of karst aquifers during geologic time periods. CAVE integrates several important features relevant for different scenarios of karst evolution: (1) the complex hydraulic interplay between flow in the karst conduits and in the small fissures of the rock matrix, (2) laminar as well as turbulent flow conditions, (3) time-dependent and nonuniform recharge to both flow systems, (4) the widening of the conduits accounting for appropriate physicochemical relationships governing calcite dissolution kinetics. This is achieved by predefining an initial network of karst conduits (''protoconduits'') which are allowed to grow according to the amount of aggressive water available due to hydraulic boundary conditions. The increase in conduit transmissivity is associated with an increase in conduit diameters while the conductivity of the fissured system is assumed to be constant in time. The importance of various parameters controlling karst genesis is demonstrated in a parameter study covering the recharge distribution, the upgradient boundary conditions for the conduit system, and the hydraulic coupling between the conduit network and the rock matrix. In particular, it is shown that conduit diameters increase in downgradient or upgradient direction depending on the spatial distribution (local versus uniform) of the recharge component which directly enters the conduit system.INDEX TERMS: 1829 Hydrology: Groundwater hydrology; 1894 Hydrology: Instruments and techniques; KEYWORDS: karst hydrology, aquifer evolution, groundwater flow, pipe flow, calcite dissolution kinetics, numerical modeling Citation: Liedl, R., M. Sauter, D. Hückinghaus, T. Clemens, and G. Teutsch, Simulation of the development of karst aquifers using a coupled continuum pipe flow model, Water Resour.

Summary Of the various enhanced-oil-recovery (EOR) polymer formulations, newly developed associative polymers show special promise. We investigate pore and pore-network scales because polymer solutions ultimately flow through the pore space of rock to displace oil. We conduct and monitor optically water/oil and polymer-solution/oil displacements in a 2D etched-silicon micromodel. The micromodel has the geometrical and topological characteristics of sandstone. Conventional hydrolyzed-polyacrylamide solutions and newly developed associative-polymer solutions with concentrations ranging from 500 to 2,500 ppm were tested. The crude oil had a viscosity of 450 cp at test conditions. Our results provide new insight regarding the ability of polymer to stabilize multiphase flow. At zero and low polymer concentrations, relatively long and wide fingers of injectant developed, leading to early water break-through and low recoveries. At increased polymer concentration, a much greater number of relatively fine fingers formed. The width-to-length ratio of these fingers was quite small, and the absolute length of fingers decreased. At a larger scale of observation, the displacement front appears to be stabilized; hence, recovery efficiency improved remarkably. Above a concentration of 1,500 ppm, plugging of the micromodel by polymer and lower oil recovery was observed for both polymer types. For tertiary polymer injection that begins at breakthrough of water, the severe fingers resulting from water injection are modified significantly. Fingers become wider and grow in the direction normal to flow as polymer solution replaces water. Apparently, improved sweep efficiency of viscous oils is possible (at this scale of investigation) even after waterflooding. The associative- and conventional-polymer solutions improved oil recovery by approximately the same amount. The associative polymers, however, showed more-stable displacement fronts in comparison to conventional-polymer solutions.

Summary Chemical enhanced oil recovery (EOR) leads to substantial incremental costs over waterflooding of oil reservoirs. Reservoirs containing oil with a high total acid number (TAN) could be produced by the injection of alkali. Alkali might lead to the generation of soaps and emulsify the oil. However, the generated emulsions are not always stable. Phase experiments are used to determine the initial amount of emulsions generated and their stability if measured over time. On the basis of the phase experiments, the minimum concentration of alkali can be determined and the concentration of alkali above which no significant increase in the formation of initial emulsions is observed. Micromodel experiments are performed to investigate the effects on the pore scale. For the injection of alkali into high-TAN oils, the mobilization of residual oil after waterflooding is seen. The oil mobilization results from the breaking up of oil ganglia or the movement of elongated ganglia through the porous medium. As the oil is depleting in surface-active components, residual oil saturation is left behind either as isolated ganglia or in the down gradient side of grains. Simultaneous injection of alkali and polymers leads to a higher incremental oil production in the micromodels owing to larger pressure drops over the oil ganglia and more-effective mobilization accordingly. Coreflood tests confirm the micromodel experiments, and additional data are derived from these tests. Alkali/cosolvent/polymer (ACP) injection leads to the highest incremental oil recovery of the chemical agents, which is difficult to differentiate in micromodel experiments. The polymer adsorption is substantially reduced if alkali is injected with polymers compared with polymer injection only. The reason is the effect of the pH on the polymers. As in the micromodels, the incremental oil recovery is also higher for alkali/polymer (AP) injection than with alkali injection only. To evaluate the incremental operating costs of the chemical agents, equivalent utility factors (EqUFs) are calculated. The EqUF takes the costs of the various chemicals into account. The lowest EqUF and, hence, the lowest chemical incremental operating expenditures are incurred by the injection of Na2CO3; however, the highest incremental recovery factor is seen with ACP injection. It should be noted that the incremental oil recovery owing to macroscopic-sweep-efficiency improvement by the polymer needs to be accounted for to assess the efficiency of the chemical agents.

About half of world oil production results from waterflooding. The remaining resources, however, are more viscous and less amenable to waterflood as conventional oil reserves are produced. In offshore and Arctic environments improved methods of cold production for viscous oil are needed because the introduction of heat to thin viscous oil appears to be unlikely. Unfavorable mobility ratio and sweep is modified by use of polymer solutions. Of the various EOR polymer formulations, newly developed associative polymers show special promise. We investigate pore and pore network scales because polymer solutions ultimately flow through the pore space of rock to displace oil. We conduct and monitor optically water/oil and polymer solution/oil displacements in a two-dimensional etched-silicon micromodel. The micromodel has the geometrical and topological characteristics of sandstone. Conventional hydrolyzed polyacrylamide solutions and newly developed associative polymer solutions with concentrations ranging from 500 ppm to 2500 ppm were tested. The crude oil had a viscosity of 210 cP at test conditions. Our results provide new insight regarding the ability of polymer to stabilize multiphase flow. At zero and low polymer concentrations, relatively long and wide fingers of injectant developed, leading to early water breakthrough and low recoveries. At increased polymer concentration, a much greater number of relatively fine fingers formed. The width to length ratio of these fingers was quite small and the absolute length of fingers decreased. At a larger scale of observation, the displacement front appears to be stabilized; hence, recovery efficiency improved remarkably. Above a concentration of 1500 ppm, plugging of the micromodel by polymer and lower oil recovery was observed for both polymer types. For tertiary polymer injection that begins at breakthrough of water, the severe fingers resulting from water injection are modified significantly. Fingers become wider and grow in the direction normal to flow as polymer solution replaces water. Apparently, improved sweep efficiency of viscous oils is possible (at this scale of investigation) even after water flooding. The associative and conventional polymer solutions improved oil recovery by about the same amount. The associative polymers, however, showed more stable fronts in comparison to conventional polymer solutions.

The evolution of a karst aquifer is modelled taking into account the karst groundwater flow as well as the dissolution kinetics of calcite. In particular, infiltration of water from the epikarst is simulated which controls the temporal and spatial distribution of recharge to the phreatic zone. The results show that the evolution of karst conduits is initiated in the spring. The existence of preferential flow paths leads to the evolution of highly conductive so-called dendritic cave systems, i.e., single passages which concentrate the flow and drain the catchment. With time, the amount of undersaturated water flowing directly into the conduit system is increased leading to an acceleration of the conduits enlargement. Three phases are identified for the evolution of karst aquifers: (a) an initiation stage; (b) an enlargement stage; and (c) a stagnation phase.