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Summary The leaching of a salt cavern will trigger a series of rock-fluid interactions, including salt rock dissolution, cavity expansion, and brine transport caused by convection, turbulence, and diffusion effects. These interactions have influences on one another. The primary objectives of this study include developing a 3D multiphysical coupled model for horizontal salt cavern leaching and quantifying these interactions. The species transport equation and standard κ-ε equation were combined to describe the brine transport dynamics within the cavity. Based on the velocity and concentration distribution characteristics predicted, the interface movement equation implemented with mesh deformation techniques was applied to describe the cavity expansion. Next, the Volgograd cavern monitored data were collected for model validation. The predicted results are consistent with the field data. The average relative errors are 11.0% for brine displacing concentration and 4.5% for cavity volume. The results suggest that the cavity can be divided into three regions, including the main flow region, circulation region, and reflux region. The results also suggest that the brine concentration distribution is relatively uniform. With the dissolution threshold angle and anisotropic dissolution rates considered, the resultant cavity cross section is crown top and cone bottom. The results also show that the cavity can be divided into dissolution and erosion sections according to its position relative to the injection point.

Summary Gas adsorption, desorption, and displacement occur throughout the coalbed methane (CBM) and enhanced coalbed methane (ECBM) recovery process, causing the coal pores to deform and affecting injectivity and productivity. The primary objectives of this study include determining the pressure at which the monolayer adsorption transitions to multilayer adsorption and linking the swelling strain to both classes of adsorption. In this study, the simplified local density (SLD) theory was first modified and applied to describe the characteristics of both types of adsorption and to determine the transition pressure. A strain model coupled with the SLD theory was then developed to describe adsorption-induced deformation. Next, the measured methane (CH4) and carbon dioxide (CO2) adsorption isotherms, and strain data on the same coals, were collected for model validation. Results suggest that gas adsorbed on coal surfaces at the very beginning (monolayer adsorption) and the adsorption on other gas molecules continues once the surface has been filled (multilayer adsorption). Results also suggest that swelling strain is proportional to both types of adsorption, with the multilayer case being larger than the monolayer case. This difference may be due to the additional repulsion between the adsorbate and multilayer liquid film.

Summary In this article, a more-general flow-pattern classification of oil/water two-phase flow in the horizontal wellbore is proposed first according to the theoretical analysis and previous research achievements, on the basis of which a simplification is then performed through reasonable incorporation, and the ultimate flow patterns considered for modeling are reduced to two categories containing only six standard patterns. By use of the classical two-fluid and homogeneous modeling methodologies stemming from oil/water two-phase flow in conventional pipes, combined with the simplified classification, a mechanistic model is developed to predict the flow characteristics including the flow patterns and pressure losses for oil/water two-phase variable-mass flow in the horizontal wellbore. Model implementation is performed on the basis of the universal principle that a system will stabilize to the equilibrium state of minimum energy. Overall performance of the mechanistic model is then validated against the new data sets measured upon a large-scale experimental apparatus at the China University of Petroleum (CUP), which is designed and constructed to simulate the gas/oil/water multiphase flow in horizontal wellbores with wall mass transfer. Results show that the model developed in this paper can not only properly predict the flow patterns of oil/water two-phase flow in the horizontal wellbore, but also has high prediction accuracy for the pressure drops. Compared with the new experimental data for oil/water two-phase variable-mass flow that covers a series of input water-volumetric fractions ranging from 10 to 90%, the highest absolute average percentage error of the new unified model is 12% and the whole error is 9.2%, which demonstrates an acceptable performance. Investigations conducted in this study further enrich and develop the theory of hydrodynamic calculation for oil/water flow in the horizontal wellbore with wall influx.