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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.

Coal particles caused by well drilling and completion, hydraulic fracturing, and formation pressure decreasing would migrate into the horizontal well carried by fracturing flow-back fluid, formation water and CBM, and then deposit on the low side of pipe leading to the decrease of cross section area of pipe for flow and even blocking of the pipe. The purpose of current research was to obtain the flow pattern while there was stationary solid particle bed on the low side of the pipe and an explicit equation to predict the height of solid particle bed was proposed. In this study, with the coal particle, water, and air as the solid, liquid, and gas phases respectively, gas/liquid/solid three-phase flow experiments in horizontal well were carried out and 4 crucial factors including different water flow rate, gas flow rate, coal particle size, and coal particle mass concentration were considered. Fluid's real apparent velocity was defined and used to analyze the distribution of flow pattern coordinate points. Results show that the flow pattern coordinate points determined by real gas apparent velocity and real water apparent velocity distribute near the flow pattern transition lines of Taitel and Dukler flow pattern map. Besides, coal particle size, water flow rate, and gas flow rate have obvious impact on the height of coal particle bed and the coal particle mass concentration has a negligible effect while the height of interface between gas layer and water layer is only dramatically affected by the gas flow rate. At last, an explicit equation for predicting the cross section area of coal particle bed based on the experimental data was proposed which is crucial to predict the flow pattern and calculate the pressure drop in horizontal well. The predicting cross section area of coal particle bed is in good agreement with the measured cross section area of coal particle bed and the average relative differences are 9.38% and 13.45% for stratified smooth flow and stratified wavy flow respectively. The equation is applicable for a range of coal particle size (8–30 mesh) and water apparent velocity (0.025–0.123 m/s).

Numerous oil wells, especially in their middle-late periods, are becoming less economic due to the high lifting costs and reduced recoveries. The downhole oil–water separation (DOWS) system is aimed to reduce the production cost, mitigate the environment impact, and enhance the oil recovery. However, current separators are of either poor separation effects or poor separation efficiencies. In this paper, a novel oil–water separator design is proposed based on the combination of two different flow resistance mechanisms and pipe serial-parallel theory, with the restrictive path restricting the heavier water, while the frictional path impeding the more viscous oil. Based on the combination of the flow pattern transformation criterion, homogenous model, two-fluid model, and pipe serial-parallel theory, a unified model of oil–water two-phase flow is developed to predict both the flow rate and water content distributions in different paths, which is then compared with the computational fluid dynamics (CFD) results. Unlike the CFD results, each path has a specific flow rate and water content, and as a consequence, specific flow regime and flow pattern. Both the CFD and model results show that the flow rate distributions in different paths of the separator will be adjusted automatically according to the fluid's property, while the model can also predict the water content distributions at the same time. And the average relative deviation between the CFD and model results for flow rate distribution is 14.24%, while that for water content distribution is 42.03%. Specifically, oil, being more viscous, mainly takes the restrictive path; while water, being heavier, tends to take the frictional path instead. To sum up, this autonomous function directs oil and water to different paths, hence oil and water is well separated.

When cementing horizontal wells, it is essential to keep the displacement interface steady, in order to achieve good cementing quality, especially in eccentric annuli. Considering the displacement behavior between shear-thinning fluids in a horizontal eccentric annulus, the Lattice-Boltzmann method (LBM) was used to investigate the displacement interface shape. The classical Hele-Shaw approach was used to simplify the model from 3D flow into a 2D model. In the simulations, the effects of eccentricity and density ratio on the displacement interface shape and on the interface length versus time were analyzed in detail, resulting in an understanding of the fingering mechanism. Comparison of LBM with the FLUENT solutions showed that the results with LBM are essentially in agreement. In general, a greater density ratio and a lower eccentricity will result in a shorter displacement interface i.e. better displacement in a horizontal eccentric annulus. For a given density ratio, there is an optimum eccentricity to achieve a steady interface. The study provides guidance to the design of wellbore cement jobs and demonstrates that LBM is a promising tool for modeling of the fluid displacement process.

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.

Coalbed methane (CBM) is an important part of energy in the world for its larger reserves, lower production cost. More and more countries and oil companies spent more and more money for CBM production in the past decades. Hydraulic fracturing is an important development method for the CMB production and the fracture parameters optimization is the key step for the hydraulic fracturing design. In this study, a fracture parameters optimization method is put forward which is based on the unified fracturing design (UFD) method. The maximum dimensionless productivity index and optimal dimensionless fracture flow conductivity of fractured wells for a certain proppant number are calculated, and then the optimal half-length and the width of the fracture, the dimensionless production index of fractured horizontal well are calculated correspondingly. All of the above is concluded under the condition that the non-Darcy effect in fracture is considered. Based on the result, the variation law of Reynolds number, the effective permeability, the optimal fracture half-length, the optimal fracture width and the optimum dimensionless production index to the free-gas saturation in CBM reservoir are obtained. We can conclude that the non-Darcy turbulent flow effect can decrease the proppant effective permeability in the fractures by mean of the generation of additional pressure drop, which will decrease the fracture diverting capacity and the production rate.

The prediction accuracy of the five horizontal wellbore single-phase drop models (Siwon, Asheim, Su, Yuan, Ouyang) is evaluated and compared based on the high-quality experimental data measured by a self-developed experimental system with large size horizontal wellbore (ID: 139.7 mm). The results show that the pressure drop prediction accuracy of the five models is, from high to low, Ouyang, Siwon, Asheim, Yuan, and Su. Generally, the Su and Yuan models have high predictions and the Siwon and Asheim model have low predictions. The Ouyang model has good prediction performance, its average relative error is only 5.5%, and the example also proves its good prediction effect, but it can't represent complex mechanisms such as the resistance effect caused by wall perforation. The models for predicting the pressure drop of single-phase flow in a horizontal wellbore need to be further improved to completely represent complex mechanisms of the variable mass flow in the horizontal wellbore, such as the resistance effect caused by wall perforation and lubrication flow drag reduction effect caused by wall influx. Key words: pressure drop model, horizontal wellbore, perforated completion, large-scale wellbore, prediction accuracy evaluation

In long horizontal wells, premature water or gas breakthrough is usually encountered due to the imbalanced production profile. This imbalanced phenomenon could be caused by the heel–toe effect, reservoir anisotropy, reservoir heterogeneity or natural fractures. Once coning occurs, water/gas fast track will be generated, leading to the reduction in oil production. Inflow control devices (ICDs) are usually installed in the completion sections to maintain a uniform inflow by generating an additional pressure loss. However, none of current ICDs are perfect enough to meet all the ideal requirements throughout the well׳s life. In this paper, a novel autonomous inflow control device (AICD) design is proposed based on the combination of two fluid dynamic components, with the splitter directing the flow, and the restrictor restricting the flow. Based on the combination of the flow pattern transformation criterion, homogenous model, two-fluid model, and pipe serial–parallel theory, a unified model of oil–water two-phase flow is developed to predict both the flow distributions and pressure drops through the splitter, which is then compared with the computational fluid dynamics (CFD) results. Also the rules of oil–water two-phase flow through the disk-shaped restrictor are studied by numerical simulation. The results show that the unified model compares well with the CFD results. The average error percentage between the model and CFD results for flow distribution is 10.02%, while that for pressure drop is 11.25%. Both the model and CFD results show that the flow distributions in different paths of the splitter will be adjusted automatically according to the fluid׳s specific property, thus different fluids will enter the restrictor differently, and result in varying flow resistances. Specifically, oil, being more viscous, tends to take the restrictive path, enter the restrictor radially, and result in minimal flow restriction; while water, being less viscous, tends to take the frictional path, enter the restrictor tangentially, begin spinning rapidly near the exit, and result in obvious flow restriction. This autonomous function enables the well to continue producing oil for a longer time while limiting the water production; hence the total oil production is maximized. The investigation conducted in this study also further enriches the theory of hydrodynamic calculation for oil–water two-phase flow in complex pipelines.

Multi-layered CBM (Coalbed Methane) reservoirs contain dozens (20–40) of thin coal seams (0.5 m–10 m) and sandstone seams and a commingled production strategy is preferred. Gas crossflow between coal seams and sandstone seams contributes much to the commingled gas production. Our study is focused on gas crossflow between coal and sandstone with fused interface. The experimental apparatus designed for this study consisted of a sandstone sample holder and a coal sample holder, where nitrogen was injected at a constant pressure difference between the sandstone and coal. The gas crossflow rate between coal and sandstone was monitored. Factors including confining stress, effective horizontal stress, axial stress and the permeability of sandstone influencing the gas crossflow were analyzed based on the experimental results. Based on the interface characteristics, a crossflow model for fused interface between coal and sandstone was proposed and gas crossflow resistant coefficients were defined. The experimental results show that gas crossflow rates decreased dramatically with the increment of confining stresses loading on the coal sample and increased linearly with the increment of average pore pressure on the condition of constant effective horizontal stresses. Compared with stresses loading on sandstone samples, the axial stresses and confining stresses loading on coal make larger influence on the gas crossflow rates. With the increment of the sandstone permeability, gas crossflow rates become less sensitive to the change of sandstone permeability. The comparison between model results and experimental results demonstrate that the proposed mathematical models can effectively predict gas crossflow between coal and sandstone with fused interface.