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Understanding stress and/or temperature sensitivity on permeability helps in predicting permeability distribution in space and its change with production. While permeability evolution with pressure...

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).

Oil-water two-phase flow through the complex pipeline, consisting of varying pipes and fittings in series or parallel, is commonly encountered in the petroleum industry. However, the majority of the current study is mainly limited to single constant-radius pipe. In this paper, a unified model of oil-water two-phase flow in the complex pipeline is developed based on the combination of pipe serial-parallel theory, flow pattern transformation criterion, two-fluid model, and homogenous model. A case is present to verify the unified model and compare with CFD results. The results show that the proposed unified model can achieve excellent performance in predicting both the flow distributions and pressure drops of oil-water two-phase flow in the complex pipeline. Compared with CFD results for water volumetric fractions ranging from 0% to 100%, the highest absolute percentage error of the proposed model is 14.4% and the average is 9.8%.

In coal-bed methane (CBM) horizontal wells, coal particles generally deposit on the low side of the wellbore to form a particle bed, which increases well pressure loss and even blocks the well. The coal particle bed undergoes changes in height and geometry with the fluctuation of gas and water production. Besides, with a low water flow rate, the water layer in CBM well is extremely thin. Both the dynamically changing particle bed and thin water layer make the conventional gas/water interfacial friction factor (fi) prediction method for stratified flow in horizontal pipe not suitable for that of CBM well. Based on the large-size multiphase complex flow experimental equipment, a gas/liquid/solid three- phase flow experiment in horizontal pipe was carried out. In the experiment, gas flow rate, water flow rate and coal particle size were the three main factors considered. During the experiment, the gas/water flow pattern, migration of coal particles and evolution of blocked section could be investigated through the transparent pipe. Furthermore, due to the significant effect of coal particle bed on the height of gas-water interface, a non-negligible gravitational pressure drop calculated using water level differences is taken into consideration when obtaining the friction pressure drop. In the experiment, three gas/water flow patterns including slug flow, stratified smooth flow and stratified wavy flow were observed. The coal particles mainly transport by means of rolling and saltating in the thin water layer under stratified flow and migrate by way of dispersing in water under slug flow. Besides, for particles no larger than 20-30 mesh, the blocked section tended to be overall driven forward like fluid by local high differential pressure and then led to the discontinuity of coal particle bed. However, for blocked section with particles not less than 10-20 mesh, instead of being driven forward, the coal particles on the top surface of it would be carried away layer by layer until the raised part was eroded off. Furthermore, as with the situation in gas/liquid two-phase stratified flow in horizontal pipe, fi in the experiment increases with liquid Reynolds number (ReL). However, it is much larger than that of gas/liquid stratified flow under the same ReL,. The analysis of experimental data presents a closely negative correlation between fi and the equivalent diameter of effective flow channel. As for the coal particle size, it has some indirect effects on fi through the equivalent diameter of effective flow channel. This work is helpful for coal particle management and productivity prediction during CBM development, which may provide guidance to particle-bailing operation and also serve as a basis for theoretical mechanistic models to predict the gas/liquid interfacial friction factor of gas/liquid/solid three-phase stratified flow.

Gas adsorption and desorption and displacement has a significant effect on coal deformation and permeability evolution during the primary recovery of coalbed methane (CBM) and enhanced coalbed methane recovery (ECBM). The objectives are to (1) quantify the coal deformation and permeability change caused by methane (CH4) displacement with carbon dioxide (CO2) and (2) model the transportation of CH4 and CO2 in deformed coalbed. In this study, the gas adsorption and desorption and displacement, coal deformation, and permeability evolution during CBM and ECBM recovery were described by an internally consistent adsorption-strain-permeability model, of which the simplified local density (SLD) adsorption theory, a theoretical strain model, and a matchstick-based permeability model were rigorous coupled. The coupled model was then verified with all of the CH4 and CO2 measured gas adsorption and desorption and coal strain data published in the past 60 years. Next, sensitivity analysis was further conducted on the ...

Natural gas produced from coals, or coalbed methane (CBM), is a significant component of the energy portfolio for many countries. One challenge associated with CBM production is associated water. Specifically, coalbeds in situ contain significant amounts of water, and ideally this water is removed by pumping prior to the primary recovery of CBM to lower pressure and stimulate methane desorption. Such a prior water production can be challenging because desorption depends on the occurrence state of methane and water in situ, e.g., how much of each fluid is adsorbed or otherwise. Accordingly, primary objectives of this analysis include quantifying both the occurrence state of methane and water of different coals for a range of coalbed properties and conditions, and specifically quantifying the impact of coal moisture on methane desorption. Ultimate and proximate analysis and methane adsorption tests were first conducted on several coal samples from different basins. Simplified local density (SLD) theory was ...

Recovery of coalbed methane (CBM) can trigger a series of coal-gas interactions, including methane desorption, coal deformation, and associated permeability change. These processes may impact each other. A primary objective of this analysis is to simultaneously quantify these interactions and their impacts during CBM recovery. To achieve this and other objectives, a rigorously coupled adsorption–strain–permeability model was developed. Gas adsorption, coal deformation, and cleat permeability characteristics were described using simplified local density (SLD) adsorption theory, a theory-based strain model, and matchstick-based permeability models, respectively. The strain model was verified against measured methane-adsorption-induced coal strain data published during the past 60 years, and the coupled model was tested using well test data measured in the San Juan Basin of New Mexico in the United States. Results suggest that the strain model is very consistent with measured coal deformation data for fluid ...

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.

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.

The Autonomous Inflow Control Device (AICD) adjusts the inflow of the horizontal wellbore by adding additional resistance to the fluid, thereby prolonging the water seepage time and enhancing oil recovery. The performance of AICD mainly depends on structural parameters. The computational fluid dynamics software is used to analyze the influence of structural parameters on the performance of AICD. The results show that the diameter of the variable diameter section, the diameter of the restrictor and the diameter of the outlet are the main factors affecting the performance of the inflow control device. The fluid parameter sensitivity simulation results show that the oil phase viscosity and water content have a great influence on the performance of AICD, while the influence of oil phase density on the performance of the device is negligible; the pressure drop under the pure water condition of this type of AICD is more than twice that of pure oil condition, so it has better water control ability.

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 lower the production cost, reduce 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 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 error for flow distribution is 17.71%, while that for water content distribution is 32.66%. 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.