Wellbore Flow Research Articles

Unsteady model for wellbore pressure transmission of carbon dioxide fracturing considering limited-flow outlet

The outlet flow rate is limited during CO2 fracturing, which significantly affects the CO2 property distribution and pressure transmission in the wellbore. In this paper, a transient wellbore flow model with a limited-flow outlet is developed to simulate the pressurization process of CO2 injection, which incorporates the compressible fluid flow governing equations, CO2 compressibility, and wellbore heat transfer. The calculation results show a good accordance with field data. The results show that the wellbore pressure and pressurization rate increase gradually with CO2 injecting under a constant inlet pump rate, and the variations in CO2 crucial properties are dominated by borehole pressurization with time increasing. Regarding the two injection patterns, a larger pressurization rate can be obtained under a lower inlet pump rate for tubing injection, while the friction pressure loss can be effectively reduced for commingled injection. Moreover, the pressurization rate increases with inlet pump rate, but also the frictional ratio and its growth rate, hence, the inlet pump rate should not be excessive. Furthermore, the inlet pressure must exceed a lower limit to prevent CO2 from gasifying, which is 4.52 MPa under the calculation condition. The model can provide more insights for the design, control, and optimization of CO2 fracturing.

A review of mathematical models for geothermal wellbore simulation

A wellbore simulator is an important tool for understanding flow in geothermal wells, however, the literature on the topic is confusing because previous wellbore simulators have been based on a variety of versions of the equations for conservation of mass, momentum and energy. This lack of consistency in describing the behaviour of flow in a geothermal well makes it unclear as to whether some models correctly conserve key quantities and presents difficulties when comparing models. This study aims to give clarity by providing a comprehensive review of conservation equations used in modelling both transient and steady multiphase flow in a geothermal wellbore.We present as a standard for comparison a complete, physically accurate three-equation model for transient flow in a geothermal wellbore. Two of the four previous transient geothermal wellbore simulators use this three-equation model, while the other two simulators are based on approximate equations that do not fully conserve all quantities.We also review previous steady-state geothermal wellbore simulators and find that some are based on mathematical models that do not correctly conserve key quantities. Some models approximate the momentum flux term using average variables, while others incorrectly account for the effect of changes in cross-sectional area on momentum flux. Our analysis shows that both assumptions can have a significant impact on simulation results under certain conditions, however, under normal operating conditions, these differences are relatively small.

Drainage effect of internal vortex tool based on experiment and numerical simulation

ABSTRACT The liquid loading at the bottom of horizontal gas well is a problem that has a significant influence on the productivity of gas well. Therefore, it is necessary to take some measures of drainage gas recovery to reduce liquid loading in wellbore and increase gas production. To evaluate the drainage effect of the internal vortex tool, which is a new drainage gas recovery tool, firstly, under the conditions of different water-gas ratios, a horizontal well laboratory simulation experiment device was used to simulate the flow state and liquid loading of the gas-liquid two-phase fluid in the wellbore before and after loading the internal vortex tool. The experimental results indicate that the internal vortex tool can effectively decrease wellbore liquid loading, improve wellbore fluid flow pattern and reduce production pressure drop. Secondly, the numerical simulation method is used to study the flow of gas-liquid two-phase and pressure drop amplitude under different gas and liquid flow conditions. Finally, the results of laboratory experiment were compared with numerical simulation, and it was found that the pressure drop amplitude error was between 6.18%~9.32%, both within 10%, which met the error requirements. It was proved that the application of internal vortex tool could effectively increase the productivity of gas wells.

Transient non-isothermal coupled wellbore-reservoir modeling of CO2 injection — Application to CO2 injection tests at the CaMI FRS site, Alberta, Canada

We investigate the dynamics of a CO2 injection wellbore using a fully-coupled non-isothermal transient multiphase wellbore-reservoir flow model. The focus of this study is on the transient behavior of the wellbore parameters in injection tests undertaken at the CaMI Field Research Station (FRS) in Alberta, Canada. Wellbore transient pressure and temperature and subsequent CO2 phase behavior through the wellbore were analyzed, and the impacts of the reservoir parameters on the wellbore transient flow behavior are characterized. Our results show that the presence of gas-liquid transient flow in the wellbore and the subsequent liquid CO2 build-up in the wellbore significantly increases the bottom hole pressure. The results show that the mean permeability of the target formation layer represents the most important controlling effect on the wellbore transient functions. We used the concepts and understanding developed through the wellbore flow dynamics characterization and the sensitivity analysis to redesign injection tests to control the CO2 wellbore transient flow. We also performed history-matching of the injection tests to examine various combinations of porosity and permeability multipliers in an attempt to match the historical pressure and temperature data obtained during the CO2 injection tests. The outcomes of this study provide an improved understanding of the transient wellbore behavior during CO2 injection over certain pressure-temperature ranges. Results developed here may be used to monitor the injection performance, well and reservoir responses under different injection scenarios.

Computational study of two-phase flashing flow in a calcite scaled geothermal wellbore

This work presents a computational study to understand different heat transfer and phase transition processes of two-phase flow in a geothermal wellbore. The simulation uses a six-equation model with mass, momentum, and energy balance equations for the liquid and vapour phase, which is available in Ansys Fluent. The model considers the effect of phase transition due to flashing, caused by thermal non-equilibrium at the liquid-vapour interface. Two wellbore scenarios, one with a constant inner diameter and the other a variable inner diameter along the flow direction due to calcite scaling, were simulated using the model. Comparison of the simulation results with measured pressure log data shows good agreement. Simulation studies for the fluid flow in a wellbore with variable diameter occurring due to calcite scaling shows higher mass transfer rate and wall normal bubble flux in the region of scaling, resulting in higher chances of mineral precipitation and deposition in the same region.

Research on flow of sour gas mixture in deep well annulus

Pressure control of oil and gas wells in high-sulfur natural gas reservoirs (well control) is critical in oil and gas drilling. Well control accidents have caused great losses of life and property. From 1960 to 1996, more than 1,120 blowout accidents occurred in the Gulf of Mexico and neighboring state capitals. Studying the principles of annulus flow with sour gas can help in early monitoring of overflow and provide theoretical guidance in actual drilling. Research of gas properties and phase behavior can reveal the reasons that sour gas is prone to blowout. The fluid flow principles of the annulus are analyzed with different contents of sour gas. In this study, a multiphase flow model of sour gas in the annulus is established based on sour gas solubility and critical parameters. The model is used to calculate and analyze the changes in sour gas properties and wellbore flow parameters with well depth. It was found that when high-content sour gas overflows, the gas expands violently near the wellhead, and the risk of blowout increases.

A fully implicit EOS based compositional two-phase transient flow simulator in wellbores

Transient two-phase flow in pipes and wellbores appears in several processes in petroleum industry. Predicting pressure, temperature and composition behavior during offshore well tests can support investment decisions in exploration. The governing system of equations that model production (or injection) and build-up (or fall off) is composed by the mass conservation of each component, the transport equation for each phase and one overall system energy equation. In this paper we develop a fully implicit equation of state based thermal compositional simulator able to model two-phase multicomponent flow in wellbores and pipes. This simulator is fully compositional and includes thermal effects. The thermodynamics calculations are based on the Peng-Robinson equation of state, and the momentum equations are based on the Single-Pressure Two-Fluid model. The finite volume method is used to discretize the non-linear system of equations, and time is discretized using Euler's implicit technique. The obtained numerical solutions for both co-current as well as countercurrent flow showed excellent agreement when compared to benchmark solutions published in the literature. A well kick-off followed by constant flow rate production and posterior shut-in was also simulated and the numerical results were discussed. It also models surge pressure and gravitational segregation effects in the wellbore. The presented simulator may be applied in numerical pressure transient analysis and pressure behavior in flowlines connecting wellheads and production platforms.

Modelling borehole flows from Distributed Temperature Sensing data to monitor groundwater dynamics in fractured media

Fractured aquifers are known to be very heterogeneous with complex flow path geometries. Their characterization and monitoring remain challenging despite the importance to better understand their behavior at all spatial and temporal scales. Heat and correspondingly temperature data have gained much interest in recent years and are often used as a tracer for characterizing groundwater flows. In the current work, a fast computer code is developed using Ramey and Hassan and Kabir analytical solutions which converts the temperature profile to the flow rate profile along the borehole. The method developed is validated through numerical simulations. A global sensitivity study recognizes the media thermal properties as the most influential parameters. For testing the method in the field, fiber-optic distributed temperature sensing (FO-DTS) data were used to monitor the dynamic behavior of fractured aquifers at the borehole scale at the Ploemeur-Guidel field site in Brittany, France. DTS data are used to infer the flow rates in the different sections of a fractured wellbore (flow profile) and calculate the contribution of each fracture to the total flow. DTS data were acquired for about three days in three different hydraulic conditions corresponding to two different ambient flow conditions and one pumping condition. Flow profiling using distributed temperature data matches satisfactorily with results from heat-pulse flow metering performed in parallel for cross-checking. Moreover, flow profiling reveals the daily variations of ambient flow in this fractured borehole. Furthermore, it shows that during ambient flowing conditions, shallow and deep fractures contribute roughly equally to the total flow while during the pumping condition, the deepest fractures contribute more to the total flow, suggesting a possible reorganization of flow and hydraulic heads depending on the hydraulic conditions. Thus, although the proposed method (DTS data and proposed framework) may be costlier and is based on indirect characterization through temperature measurements, it provides real-time monitoring of complex fracture interactions and recharge processes in fractured media. Thus, this method allows for a full analysis of the temporal behavior of the system with a simple and fast analytical model. Furthermore, thanks to its narrow width, DTS can be used and installed in boreholes for long-term monitoring while heat-pulse flow metering may lead to head losses in the borehole and may not be always possible depending on some borehole conditions. One of the limitations of the approach proposed is the proper knowledge of the thermal properties of media required to infer the flow rate from the temperature. Nevertheless, surface rate measurement can be useful to constrain these properties and reduce the flow profiling uncertainty. Thus, the method proposed appears to be an interesting and complementary method for characterizing borehole flows and groundwater dynamics in fractured media such as for instance, monitoring the recharge dynamic.

Research on calculation model of bottom of the well pressure based on machine learning

Based on the research on the calculation model of the bottom of the well pressure of the Managed Pressure Drilling, a set of accurate and effective monitoring methods for the bottom of the well pressure of the Managed Pressure Drilling is proposed.Through the analysis of the hydraulic model, the feasibility of the artificial intelligence algorithm in the bottom of the well pressure calculation and monitoring method is studied. Based on the analysis of the wellbore flow hydraulic model, the simulated annealing (SA) algorithm is combined with the support vector regression (SVR) machine to establish a set based on the simulated annealing algorithm to improving the supported vector regression machine (SA-SVR) is used to optimize the monitoring method of bottom of the well pressure of Managed Pressure Drilling (MPD).Combining the hydrostatic column pressure, Annulus pressure loss and surface back pressure data, Managed Pressure Drilling bottom of the well pressure monitoring model based machine learning is constructed to realize bottom of the well pressure data monitoring without PWD (Pressure While Drilling) instruments. The bottom of the well pressure monitoring model based on machine learning is used to calculate and analyze the bottom of the well pressure, provide theoretical support for Bottom of the well pressure monitoring of drilling operations, and guide safe drilling at the construction site.

Prediction of Heavy Oil Steam Stimulation Based on Data-Driven and Mechanism Model

In the middle and late stages of heavy oil development, formulating a scientific and reasonable mining plan is the key to improving oilfield efficiency. At present, steam stimulation is still the main development method of heavy oil. The determination of its production is not only limited by boiler conditions, surface pipelines, and wellbore conditions but also by the steam absorption capacity of the formation. Therefore, local analysis cannot achieve the best effect in the whole process of steam stimulation. The mechanism model is the most commonly used method to predict heavy oil production, but too many idealized assumptions make the prediction results quite different from the actual production situation. With the rapid development of machine learning, people can achieve rapid prediction of production through field data. However, when the range of the actual parameter is small, the generalization ability of the model is weak and overfitting occurs. Based on the above background, this paper conducts a coupling study on surface steam pipeline flow, steam injection wellbore flow, and formation flow from the perspective of data-driven. Firstly, based on the correlation coefficient and the feature selection of Random Forest, the importance of the characteristics affecting liquid production and water content was ranked. Secondly, through the comparison of five typical machine learning algorithms, we select the optimal prediction model and optimal characteristics suitable for the sample of this paper. Finally, because of the poor generalization ability of the prediction model, we sampled the mechanism model and increased the diversity of steam dryness samples. We find that the accuracy of the optimal prediction model is improved and the generalization ability of the model is improved after the training of new samples. This paper provides a new idea for the production prediction of heavy oil steam stimulation reservoirs, which is helpful for the efficient development of heavy oil reservoirs.

Simple and Robust Algorithm for Multiphase Equilibrium Computations at Temperature and Volume Specifications

Summary Two-phase and three-phase equilibria are frequently encountered in a variety of industrial processes, such as carbon dioxide (CO2) injection for enhanced oil recovery in oil reservoirs, multiphase separation in surface separators, and multiphase flow in wellbores and pipelines. Simulation and engineering design of these processes using isothermal/isochoric (VT) multiphase equilibrium algorithms are sometimes more convenient than that using the conventional isothermal/isobaric (PT) algorithms. This work develops a robust algorithm for VT multiphase equilibrium calculations using a nested approach. The proposed algorithm is simple because a robust PT multiphase equilibrium algorithm is used in the inner loop without any further modifications, while an effective equation-solving method (i.e., Brent’s method; Brent 1971) is applied in the outer loop to solve the pressure corresponding to a given volume/temperature specification. The robustness of the VT algorithm is safeguarded by using a highly efficient trust-region-method-based PT algorithm. We demonstrate the good performance of the newly developed algorithm by applying it to calculate the isochores of fluid mixtures that exhibit both two-phase and three-phaseequilibria.

The coupled model of wellbore temperature and pressure for variable gradient drilling in deep water based on dynamic mass flow

Variable gradient drilling in deep water is a new drilling method of using separators to separate hollow glass spheres (Referred to as HGS, it is the glass microbeads with low density less than 1.0 kg/m3, and the worse thermal conductivity) from the drill string directly into the annulus, which can form multiple gradients of drilling fluid density in annulus. This method can better deal with the problem of narrow pressure window in deep water drilling. At present, there are few studies on the wellbore temperature and pressure distribution of this technology, and the separation efficiency of the existing separator is too low to achieve variable gradient. The purpose of this paper is to develop a new separator to improve the separation efficiency, and to study the coupled wellbore temperature and pressure field of variable gradient drilling based on dynamic mass flow. Firstly, indoor simulated experiments were used to study the separation efficiency of the newly developed filter separator, and based on the separation efficiency, wellbore flow theory and the first law of thermodynamics, the dynamic mass flow at the location of the separator were fully considered. Considering the influence of wellbore temperature and pressure on thermophysical parameters, a coupled model of wellbore temperature and pressure was established based on dynamic mass flow. Then the model was discretized and solved by finite difference method and cyclic iterative algorithm. Further, this model was verified based on the existing models and drilling site data. Finally, the effects of key parameters in variable gradient drilling on the annulus temperature, pressure and fluid density were studied. The results show that the filter separator has high feasibility, and the separation efficiency can reach 95%–98.5%. Compared with conventional drilling, distribution curve of the temperature, pressure and the mixture density in annulus of the filter separator section has obvious inflection points in variable gradient drilling, and the number of inflection points is equal to the number of separators. What's more, the number and location of separators, the HGS volume fraction, pump flow rate, and the HGS density have significant effects on the annulus temperature and pressure. This research can significantly improve the feasibility of variable gradient drilling in deep water and provide a theoretical reference for further research in this direction.

A multi-tracer and well-bore flow profile approach to determine occurrence, movement, and sources of perchlorate in groundwater

The purpose of this study is to determine the occurrence, movement, and sources of perchlorate in groundwater using a comprehensive set of environmental tracers coupled with discrete borehole data. Potential sources of perchlorate to groundwater at the study site have been attributed to waste disposal and industrial activities as well as to past agricultural operations. Perchlorate concentrations in samples ranged from <1 to 40 μg/l, with a median of 6.1 μg/l. Concentrations were relativity consistent with depth except at one site where dilution may be occurring due to the infiltration of surface water from Pyrite Creek. Well-bore flow profiles indicated that perchlorate redistribution was occurring via intra-well bore flow at one site where up to 14,000 mg/year of perchlorate could be moving from the shallower to the deeper zones of the alluvial aquifer. Natural attenuation processes of perchlorate do not appear to be widespread in groundwater but do occur in portions of the aquifer adjacent to the Santa Ana River, likely limiting the mobility of perchlorate from the southernmost extent of the mapped plume to areas farther down-gradient. Age dating tracers indicate that the advective transport of perchlorate originating from the waste disposal ponds has largely moved through the zones of the aquifer sampled. Age distributions, noble gas temperature, delta neon values and stable isotopes of water indicate that a substantial fraction of perchlorate in groundwater may have been mobilized from the unsaturated zone and/or is from the infiltration of storm water runoff originating from Pyrite Canyon.

Study on foam transport mechanism and influencing factors in foam drainage gas recovery of natural gas well

In order to study the distribution and flow pattern of foam in the wellbore during the process of foam drainage and gas recovery, A coupled model of gas and foam flow in wellbore was established. The distribution characteristics of foam in the wellbore during the process of foam drainage and gas recovery were analyzed through experiments. The concept of foaming efficiency and bubble carrying efficiency were introduced, and the drainage time and liquid accumulation time of foam drainage gas recovery in wellbore were calculated. The research results show that: In the process of foam drainage, there are two states of heterogeneous foam flow and homogeneous foam flow in the wellbore. Under the influence of the high flow rate of natural gas in the wellbore, the migration rate of bubbles near the wellbore is slow. High gas yield and low bubble density are beneficial to the rapid initiation of foam. Due to the double influence of gas carrying force and gravity, bubbles will show relatively complex motion characteristics, and the fluid level height in the wellbore is linearly related to time under different influencing factors in the process of gas well drainage. The research in this article is of great significance for precise drainage of foam drainage gas recovery.

A coupling flow model for fractured horizontal well and anisotropic tight gas reservoir

The development of multistage fracturing technology in horizontal wells is a great impulsion to the successful development of unconventional resources. The hydraulic fractures distribute regularly along the horizontal wellbore, forming a seepage channel for fluids in tight gas reservoir and greatly improving the productivity of horizontal wells. Based on Green function and Neumann product principle, we establish a flow model of fractured horizontal well coupled with anisotropic tight gas reservoir under both unsteady state and pseudo-steady state and propose a method to solve this model. The calculation results show that flow rate of horizontal well under the early unsteady state is larger than that under the pseudo-steady state. There is no interference among fractures in the early unsteady state, and flow rate is in direct proportion to fracture numbers. Affected by frictional and acceleration pressure drop, flow rate of the end fractures is obviously larger than other fractures in pseudo-steady state. The permeabilities in different directions have great influence on well flow rate distribution. With the increasing Kx, the interference between the fractures is reduced, and the flow distribution is more balanced. When Ky becomes larger, the interference between fractures are stronger, and the “U” shape distribution of the wellbore flow is more significant.

An Integrated Simulation Approach for Wellbore Blockage Considering Precipitation, Aggregation, and Deposition of Asphaltene Particles

Summary Asphaltene deposition triggers serious flow assurance issues and can significantly restrict the production capacity. Because of the complexity associated with asphaltene deposition that includes several mechanisms acting simultaneously, an accurate prediction of asphaltene blockage along the wellbore requires integration of asphaltene precipitation, aggregation, and deposition. In this work, an integrated simulation approach is proposed to predict the asphaltene deposition profile along the wellbore. The proposed approach is novel because it integrates various deposition patterns of particulate flow (which depends on hydrodynamics) with aggregation processes to investigate how the distribution of asphaltene particle size varies (governed by molecular dynamics) after being precipitated out of the oil phase (controlled by thermodynamics). To improve the predictability capability of simulations, a direct input from the wellbore flow simulator is used to update the velocity profile after the wellbore radius changes beyond a certain predefined threshold. The fraction of asphaltene precipitation is determined using the asphaltene solubility model and combined with aggregation models to feed into deposition calculations. Wellbore blockage was examined for two cases with and without the aggregation mechanism included. A sensitivity analysis was carried out to study parameters that affect the severity of blockage, such as range of pressure-temperature along the wellbore, flow velocity, and radial distribution of asphaltene particles. The simulation approach proposed in this paper provides an in-depth understanding of the wellbore flow assurance issues caused by asphaltene deposition and thus provides useful insights for improving the predictions of production performance.

Poroelastoplastic Modeling of Complex Hydraulic-Fracture Development in Deep Shale Formations

Summary In this paper, we propose a hydromechanical model to simulate hydraulic fracture propagation in deep shale formations. The Drucker-Prager plasticity theory, Darcy’s law, Reynolds lubrication theory, and Kirchoff’s laws are adopted to describe the plastic deformation, matrix flow, fracture flow, and wellbore flow, respectively. A global embedded cohesive zone model is constructed to achieve the free evolution of hydraulic fractures and the characterization of natural fractures. The finite element method (FEM) and finite volume method (FVM) are used for the spatial discretization of the stress field and pressure field. On the basis of Newton-Raphson iteration, fixed-stress iteration, and Picard iteration, a mixed numerical scheme is built up to solve the strong nonlinear coupling problem. The proposed model is verified against several reference cases and experimental results. Finally, some numerical cases are carried out to investigate the influences of rock properties, natural fracture distribution, and fracturing fluid properties on the complex hydraulic fracture development. The results show that rock plasticity leads to a decrease in stimulated fracture area, an increase in average fracture width, and an increase in propagation pressure. As the cluster number increases, the adverse effect of rock plasticity on multiple hydraulic fracturing in deep shale formations increases significantly. In addition, appropriate optimization of cluster spacing could weaken the adverse effect of rock plasticity on fracturing treatment to a certain extent by using the stress interference effect.

Reservoir and Wellbore Flow Coupling Model for Fishbone Multilateral Wells in Bottom Water Drive Reservoirs

AbstractNowadays, different types of complex production wells are applied in challenging reservoirs in order to maximize oil recovery. A representative application is the fishbone multilateral horizontal wells, which have advantages of expanding the drainage area information and reducing the pressure loss in the long single lateral wellbore. This paper investigated the performance of fishbone wells and derived a wellbore and reservoir flow coupling model for fishbone multilateral wells in the bottom water reservoirs. The new model considered plenty of parameters that may have significant impacts on productivity and pressure drop in the well, including the fishbone structure, the main and branch wellbores’ length, the spacing distance of the branch wellbores, wellbore radius, and preformation parameters. Furthermore, a sensitivity analysis example by the numerical method is presented in this paper. Compared with other models, our coupling model, when it is degraded to horizontal well, is more consistent with the results of actual field situation. In another comparative analysis, the results of the new model with branches show a good match with the numerical simulation results by software. The proposed method in this paper can be used as a valuable tool to analyze the productivity, wellbore inflow profile, and pressure profile of the fishbone multilateral wells in the bottom water reservoir.

A New Approach to Embed Complex Fracture Network in Tight Oil Reservoir and Well Productivity Analysis

Accurate modeling of the distribution of induced fractures and pre-existing natural ones in unconventional reservoirs is essential for the analysis of the productivity of horizontal wells after fracturing. A novel approach is proposed here to establish a three-dimensional geological model of induced fractures, natural fractures and the horizontal well using a discrete random distribution method, based on micro-seismic data and natural fracture properties from the S oilfield. Taking the stress sensitivity into consideration, a coupled model calculating the fluid flow in the horizontal wellbore, the reservoir matrix and fractures were established to simulate the productivity of the S oilfield. This model was calibrated by the production data in the S oilfield, and the productivity of horizontal well under different natural fracture intensities, hydraulic fracture spacing and lengths was analyzed. The results show that the area without stimulation in the tight oil reservoir can rarely be exploited. The fluid pressure in the horizontal wellbore cannot be treated as uniform, especially when the production pressure keeps decreasing; otherwise, the cumulative production will be larger than the actual one. Increasing the hydraulic fracture length and natural fracture intensity and decreasing the fracture spacing are all beneficial to the daily and cumulative oil production. However, these methods accelerate the decline of the daily production. The production decline rate with higher natural fracture intensity was about 4 times that of lower natural fracture intensity. The natural fracture intensity and the fracture spacing are factors that are more influential to the productivity compared to the fracture length.

Simulation of wellbore erosion and sand transport in long horizontal wells producing gas at high velocities

Horizontal wells play a crucial role in improving the recovery of hydrocarbons from thin reservoirs. In weakly consolidated formations, these wells may encounter sand production and this may lead to several problems including wellbore instability, production time loss, corrosion and plugging of downhole and surface facilities. Sand production in wellbores can be linked to two physical phenomena. The first is stress concentration along the wellbore causing mechanical instability and localized failure of the rock. The second is related to hydro-mechanical forces that cause internal and surface erosion, triggering the release of particles from rock surface, by the action of drag forces of produced matter. In open hole completions, high-velocity gas flow can trigger the release of particles from rock surface.We present a reservoir-wellbore flow model to simulate high-velocity gas flow in porous media and in open-hole horizontal wells. Since gas wells are associated with high-velocity flows, this study is focused on dry gas production from long open-hole wells, where large sections of wellbore wall are exposed to the stresses caused by the flowing stream of gas. The Forchheimer equation is coupled with conservation of mass to solve for gas flow in the porous media while the Bernoulli's equation is coupled with mass conservation to solve for gas flow in the horizontal wellbore. Computed wellbore velocities are then used to calculate sand erosion using the Water Erosion Prediction Project (WEPP) model. Subsequently, an advection equation is used to model the transport of the eroded sand particles in the wellbore. An example is presented to study how wellbore erosion affects the flow of gas and pressure drop in the horizontal well. The results indicate that the erosion due to high-velocity gas flow in open-hole horizontal wells affects the gas production rate as well as the well flowing pressure.