Browsing by Subject "Horizontal well"
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Item A comparative analysis of numerical simulation and analytical modeling of horizontal well cyclic steam injection(Texas A&M University, 2005-08-29) Ravago Bastardo, Delmira CristinaThe main objective of this research is to compare the performance of cyclic steam injection using horizontal wells based on the analytical model developed by Gunadi against that based on numerical simulation. For comparison, a common reservoir model was used. The reservoir model measured 330 ft long by 330 ft wide by 120 ft thick, representing half of a 5-acre drainage area, and contained oil based on the properties of the Bachaquero-01 reservoir (Venezuela). Three steam injection cycles were assumed, consisting of a 20-day injection period at 1500 BPDCWE (half-well), followed by a 10-day soak period, and a 180-day production period. Comparisons were made for two cases of the position of the horizontal well located on one side of the reservoir model: at mid-reservoir height and at reservoir base. The analytical model of Gunadi had to be modified before a reasonable agreement with simulation results could be obtained. Main modifications were as follows. First, the cold horizontal well productivity index was modified to that based on the Economides-Joshi model instead of that for a vertical well. Second, in calculating the growth of the steam zone, the end-point relative permeability??s of steam and oil were taken into consideration, instead of assuming them to be the same (as in the original model of Gunadi). Main results of the comparative analysis for both cases of horizontal well positions are as follows. First, the water production rates are in very close agreement with results obtained from simulation. Second, the oil production rates based on the analytical model (averaging 46,000 STB), however, are lower than values obtained from simulation (64,000 STB). This discrepancy is most likely due to the fact that the analytical model assumes residual oil saturation in the steam zone, while there is moveable oil based on the simulation model. Nevertheless, the analytical model may be used to give a first-pass estimate of the performance of cyclic steam injection in horizontal wells, prior to conducting more detailed thermal reservoir simulation.Item A lattice model for gas production from hydrofractured shale(2016-12) Eftekhari, Behzad; Patzek, Tadeusz W.; Marder, Michael P., 1960-; Olson, Jon E; Sepehrnoori, Kamy; Espinoza, David NNatural gas production from US shale and tight oil plays has increased over the past 10 years, currently constitutes more than half of the total US dry natural gas production, and is projected to provide the US with a major energy source in the next several decades. The increase in shale gas production is driven by advances in hydraulic fracturing. Recent studies have shown that gas production from hydraulically fractured shales has to come from a network of connected hydraulic and natural fractures, and that if one takes the shale permeability to be 10 nD, then the characteristic spacing of the fracture network will be about 1.5 − 3 m. The precise nature of the characteristic spacing, as well as other production and formation properties of the fracture network, are questions which motivated the present dissertation. This dissertation studies (1) the topology of the fracture network, (2) the mechanics of how the fracture network evolves in time during injection and (3) how fracture network geometry affects production. We use percolation theory to study fracture network topology. Fracture are placed on the bonds of a two–dimensional square lattice and follow a power law length distribution. We analytically obtain the scaling of connectivity for power law fracture networks, and numerically compute the percolation threshold as a function of the exponent. We develop a hydrofracture model which makes it possible to simulate initiation and propagation of hydraulic fractures, as well as the interaction between hydraulic and natural fractures. The model uses the Reynolds lubrication approximation to describe fluid flow through the fractures and relies on analytical estimates to predict the stress response. We develop a diffusion model to compute gas production from hydraulically fractured shales. The model uses a random walk algorithm and takes the fracture network as the absorbing boundary to the gas transport equation. We show that scaling the cumulative production versus time data from the diffusion model with respect to characteristic scales of production maps the production versus time plots onto a single scaling curve. Using the model, we identify, or define, characteristic spacing for fracture networks.Item Aquitard control of stream-aquifer interaction and flow to a horizontal well in coastal aquifers(Texas A&M University, 2007-04-25) Sun, DongminThis dissertation is composed of three parts of major contributions: In Chapter II, we developed a new conceptual model and derived a new semi-analytical model for flow to a horizontal well beneath a water reservoir. Instead of treating the leakage from aquitard as a source term inside the aquifer which is called Hantush??????s assumption (1964), we linked flows in aquitard and aquifer by the idea of continuity of flux and drawdown. The result in this chapter is compared with that of Zhan and Park in 2003 which Hantush??????s assumption is adopted at various hydraulic and well configurations. It shows that Hantush??????s assumption becomes inaccurate in regions where vertical velocity components are significant. In Chapter III, we deal with the interaction of an aquifer with two parallel surface water bodies such as two streams or canals. In this chapter, new closed-form analytical and semi-analytical solutions are acquired for the pumping induced dynamic interaction between two streams and ground water for two different cases. In the first case, the sediment layers separating the streams from the aquifer ground water do not exist. In the second case, the two low permeable layers are considered. The effect of aquitard and water right competition is addressed in this chapter. This model can be used for interpreting and deriving hydrologic parameters of aquitard and aquifer when pumping occurs between two channels. It can also be used to predict stream depletion which is essential for water management and ecology conservation. In Chapter IV, we investigated the three dimensional upconing due to a finite-length of horizontal well and its critical conditions. The results are compared with those of vertical wells. The critical condition which includes the critical rise and the critical time at a certain pumping rate depends on the well length, the initial interface location, the well location, and the pumping rate. Our results show that horizontal well might be a better tool for coastal groundwater resources development. In real field applications, installing long wells as shallow as possible is always desirable for sustaining long periods of pumping with significant rates.Item CFD-based representation of non-Newtonian polymer injectivity for a horizontal well with coupled formation-wellbore hydraulics(2010-12) Jackson, Gregory Thomas, 1983-; Balhoff, Matthew T.; Huh, ChunDuring injection of a high-viscosity, non-Newtonian polymer into a long horizontal well, a significant pressure drop occurs along the well length. Computational Fluid Dynamics (CFD) modeling of the shear-thinning flow of polymer in the wellbore, coupled with the viscoelastic flow in composite gravel-pack/near-well formation zone, was carried out to develop convenient correlations for axial pressure values of both Newtonian and non-Newtonian fluids along the well length, for use in chemical EOR simulations. The detailed CFD modeling of the non-Newtonian flow behavior of polymer within the horizontal wellbore, completion zone and the near-well formation, not only allows accurate accounting of pressure distribution along the long horizontal well, but also can be employed for screening diagnosis for possible injectivity inefficiencies resulting from non-uniform pressure values. At both high and low injection rates, CFD modeling predicts non-uniform pressure distributions for highly viscous fluids. The inclusive pressure correlation was implemented into UTCHEM, a University of Texas at Austin research simulator, to determine the importance of including pressure drop in polymer injections. Early times (i.e., less than 100 days) yielded a significant oil recovery deviation from a uniform pressure wellbore. However, at later times the recovery loss generated by the pressure decrease was deemed negligible; therefore, the traditional assumption regarding uniform pressure in horizontal wellbores was still reasonable for highly viscous non-Newtonian flow. This CFD study is the first mechanistic investigation of the polymer injectivity with detailed description of the wellbore, completion zone and near-well formation, and with full accounting of the shear-thinning rheology for pipe flow and the viscoelastic rheology of polymer in porous media. With increased use of very high molecular-weight polymers for chemical EOR processes for mobility control, the latter mechanism is known to be critical.Item Development and application of a 3D equation-of-state compositional fluid-flow simulator in cylindrical coordinates for near-wellbore phenomena(2011-12) Abdollah Pour, Roohollah; Torres-Verdín, Carlos; Sepehrnoori, Kamy, 1951-; Delshad, Mojdeh; Demkowicz, Leszek; Johns, Russell T.Well logs and formation testers are routinely used for detection and quantification of hydrocarbon reserves. Overbalanced drilling causes invasion of mud filtrate into permeable rocks, hence radial displacement of in-situ saturating fluids away from the wellbore. The spatial distribution of fluids in the near-wellbore region remains affected by a multitude of petrophysical and fluid factors originating from the process of mud-filtrate invasion. Consequently, depending on the type of drilling mud (e.g. water- and oil-base muds) and the influence of mud filtrate, well logs and formation-tester measurements are sensitive to a combination of in-situ (original) fluids and mud filtrate in addition to petrophysical properties of the invaded formations. This behavior can often impair the reliable assessment of hydrocarbon saturation and formation storage/mobility. The effect of mud-filtrate invasion on well logs and formation-tester measurements acquired in vertical wells has been extensively documented in the past. Much work is still needed to understand and quantify the influence of mud-filtrate invasion on well logs acquired in horizontal and deviated wells, where the spatial distribution of fluids in the near-wellbore region is not axial-symmetric in general, and can be appreciably affected by gravity segregation, permeability anisotropy, capillary pressure, and flow barriers. This dissertation develops a general algorithm to simulate the process of mud-filtrate invasion in vertical and deviated wells for drilling conditions that involve water- and oil-base mud. The algorithm is formulated in cylindrical coordinates to take advantage of the geometrical embedding imposed by the wellbore in the spatial distribution of fluids within invaded formations. In addition, the algorithm reproduces the formation of mudcake due to invasion in permeable formations and allows the simulation of pressure and fractional flow-rate measurements acquired with dual-packer and point-probe formation testers after the onset of invasion. An equation-of-state (EOS) formulation is invoked to simulate invasion with both water- and oil-base muds into rock formations saturated with water, oil, gas, or stable combinations of the three fluids. The algorithm also allows the simulation of physical dispersion, fluid miscibility, and wettability alteration. Discretized fluid flow equations are solved with an implicit pressure and explicit concentration (IMPEC) scheme. Thermodynamic equilibrium and mass balance, together with volume constraint equations govern the time-space evolution of molar and fluid-phase concentrations. Calculations of pressure-volume-temperature (PVT) properties of the hydrocarbon phase are performed with Peng-Robinson's equation of state. A full-tensor permeability formulation is implemented with mass balance equations to accurately model fluid flow behavior in horizontal and deviated wells. The simulator is rigorously and successfully verified with both analytical solutions and commercial simulators. Numerical simulations performed over a wide range of fluid and petrophysical conditions confirm the strong influence that well deviation angle can have on the spatial distribution of fluid saturation resulting from invasion, especially in the vicinity of flow barriers. Analysis on the effect of physical dispersion on the radial distribution of salt concentration shows that electrical resistivity logs could be greatly affected by salt dispersivity when the invading fluid has lower salinity than in-situ water. The effect of emulsifiers and oil-wetting agents present in oil-base mud was studied to quantify wettability alteration and changes in residual water saturation. It was found that wettability alteration releases a fraction of otherwise irreducible water during invasion and this causes electrical resistivity logs to exhibit an abnormal trend from shallow- to deep-sensing apparent resistivity. Simulation of formation-tester measurements acquired in deviated wells indicates that (i) invasion increases the pressure drop during both drawdown and buildup regimes, (ii) bed-boundary effects increase as the wellbore deviation angle increases, and (iii) a probe facing upward around the perimeter of the wellbore achieves the fastest fluid clean-up when the density of invading fluid is larger than that of in-situ fluid.Item Development of a coupled wellbore-reservoir compositional simulator for horizontal wells(2010-12) Shirdel, Mahdy; Sepehrnoori, Kamy, 1951-; Ribeiro, Paulo R.Two-phase flow occurs during the production of oil and gas in the wellbores. Modeling this phenomenon is important for monitoring well productivity and designing surface facilities. Since the transient time period in the wellbore is usually shorter than reservoir time steps, stabilized flow is assumed in the wellbore. As such, semi-steady state models are used for modeling wellbore flow dynamics. However, in the case that flow variations happen in a short period of time (i.e., a gas kick during drilling) the use of a transient two-phase model is crucial. Over the last few years, a number of numerical and analytical wellbore simulators have been developed to mimic wellbore-reservoir interaction. However, some issues still remain a concern in these studies. The main issues surrounding a comprehensive wellbore model consist of fluid property calculations, such as black-oil or compositional models, governing equations, such as mechanistic or correlation-based models, effect of temperature variation and non-isothermal assumption, and methods for coupling the wellbore to the reservoir. In most cases, only standalone wellbore models for blackoil have been used to simulate reservoir and wellbore dynamic interactions. Those models are based on simplified assumptions that lead to an unrealistic estimation of pressure and temperature distributions inside the well. In addition, most reservoir simulators use rough estimates for the perforation pressure as a coupling condition between the wellbore and the reservoir, neglecting pressure drops in the horizontal section. In this study, we present an implementation of a compositional, pseudo steady-state, non-isothermal, coupled wellbore-reservoir simulator for fluid flow in wellbores with a vertical section and a horizontal section embedded on the producing reservoir. In addition, we present the implementation of a pseudo-compositional, fully implicit, transient two-fluid model for two-phase flow in wellbores. In this model, we solve gas/liquid mass balance, gas/liquid momentum balance, and two-phase energy equations in order to obtain the five primary variables: liquid velocity, gas velocity, pressure, holdup and temperature. In our simulation, we compared stratified, bubbly, intermittent flow effects on pressure and temperature distributions in either a transient or steady-state condition. We found that flow geometry variation in different regimes can significantly affect the flow parameters. We also observed that there are significant differences in flow rate prediction between a coupled wellbore-reservoir simulator and a stand-alone reservoir simulator, at the early stages of production. The outcome of this research leads to a more accurate and reliable simulation of multiphase flow in the wellbore, which can be applied to surface facility design, well performance optimization, and wellbore damage estimation.Item Interpreting Horizontal Well Flow Profiles and Optimizing Well Performance by Downhole Temperature and Pressure Data(2011-02-22) Li, ZhuoyiHorizontal well temperature and pressure distributions can be measured by production logging or downhole permanent sensors, such as fiber optic distributed temperature sensors (DTS). Correct interpretation of temperature and pressure data can be used to obtain downhole flow conditions, which is key information to control and optimize horizontal well production. However, the fluid flow in the reservoir is often multiphase and complex, which makes temperature and pressure interpretation very difficult. In addition, the continuous measurement provides transient temperature behavior which increases the complexity of the problem. To interpret these measured data correctly, a comprehensive model is required. In this study, an interpretation model is developed to predict flow profile of a horizontal well from downhole temperature and pressure measurement. The model consists of a wellbore model and a reservoir model. The reservoir model can handle transient, multiphase flow and it includes a flow model and a thermal model. The calculation of the reservoir flow model is based on the streamline simulation and the calculation of reservoir thermal model is based on the finite difference method. The reservoir thermal model includes thermal expansion and viscous dissipation heating which can reflect small temperature changes caused by pressure difference. We combine the reservoir model with a horizontal well flow and temperature model as the forward model. Based on this forward model, by making the forward calculated temperature and pressure match the observed data, we can inverse temperature and pressure data to downhole flow rate profiles. Two commonly used inversion methods, Levenberg- Marquardt method and Marcov chain Monte Carlo method, are discussed in the study. Field applications illustrate the feasibility of using this model to interpret the field measured data and assist production optimization. The reservoir model also reveals the relationship between temperature behavior and reservoir permeability characteristic. The measured temperature information can help us to characterize a reservoir when the reservoir modeling is done only with limited information. The transient temperature information can be used in horizontal well optimization by controlling the flow rate until favorite temperature distribution is achieved. With temperature feedback and inflow control valves (ICVs), we developed a procedure of using DTS data to optimize horizontal well performance. The synthetic examples show that this method is useful at a certain level of temperature resolution and data noise.Item Investigation of the effects of buoyancy and heterogeneity on the performance of surfactant floods(2014-12) Tavassoli, Shayan; Pope, G. A.; Sepehrnoori, Kamy, 1951-The primary objectives of this research were to understand the potential for gravity-stable surfactant floods for enhanced oil recovery without the need for mobility control agents and to optimize the performance of such floods. Surfactants are added to injected water to mobilize the residual oil and increase the oil production. Surfactants reduce the interfacial tension (IFT) between oil and water. This reduction in IFT reduces the capillary pressure and thus the residual oil saturation, which then results in an increase in the water relative permeability. The mobility of the surfactant solution is then greater than the mobility of the oil bank it is displacing. This unfavorable mobility ratio can lead to hydrodynamic instabilities (fingering). The presence of these instabilities results in low reservoir sweep efficiency. Fingering can be prevented by increasing the viscosity of the surfactant solution or by using gravity to stabilize the displacement below a critical velocity. The former can be accomplished by using mobility control agents such as polymer or foam. The latter is called gravity-stable surfactant flooding, which is the subject of this study. Gravity-stable surfactant flooding is an attractive alternative to surfactant polymer flooding under certain favorable reservoir conditions. However, a gravity-stable flood requires a low velocity less than the critical velocity. Classical stability theory predicts the critical velocity needed to stabilize a miscible flood by gravity forces. This theory was tested for surfactant floods with ultralow interfacial tension and found to over-estimate the critical velocity compared to both laboratory displacement experiments and fine-grid simulations. Predictions using classical stability theory for miscible floods were not accurate because this theory did not take into account the specific physics of surfactant flooding. Stability criteria for gravity-stable surfactant flooding were developed and validated by comparison with both experiments and fine-grid numerical simulations. The effects of vertical permeability, oil viscosity and heterogeneity were investigated. Reasonable values of critical velocity require a high vertical permeability without any continuous barriers to vertical flow in the reservoir. This capability to predict when and under what reservoir conditions a gravity-stable surfactant flood can be performed at a reasonable velocity is highly significant. Numerical simulations were also used to show how gravity-stable surfactant flooding can be optimized to increase critical velocity, which shortens the project life and improves the economics of the process. The critical velocity for a stable surfactant flood is a function of the microemulsion viscosity and it turns out there is an optimum value that can be used to significantly increase the velocity and maintain stability. For example, the salinity gradient can be optimized to gradually decrease the microemulsion viscosity. Another alternative is to inject a polymer drive following the surfactant solution, but using polymer complicates the process and adds to its cost without significant benefit in most gravity-stable surfactant floods. A systematic approach was introduced to make decisions on using polymer in applications based on stability criteria and cost. Also, the effect of an aquifer on gravity-stable surfactant floods was investigated as part of a field-scale study and strategies were developed to minimize its effect on the process. This study has provided new insights into the design of an optimized gravity-stable surfactant flood. The results of the numerical simulations show the potential for high oil recovery from gravity-stable surfactant floods using horizontal wells. Application of gravity-stable surfactant floods reduces the cost and complexity of the process. The widespread use of horizontal wells has greatly increased the attractiveness and potential for conducting surfactant floods in a gravity-stable mode. This research has provided the necessary criteria and tools needed to determine when gravity-stable surfactant flooding is an attractive alternative to conventional surfactant-polymer flooding.Item Real-Time Evaluation of Stimulation and Diversion in Horizontal Wells(2012-02-14) Tabatabaei Bafruei, Seyed MohammadOptimum fluid placement is crucial for successful acid stimulation treatments of long horizontal wells where there is a broad variation of reservoir properties along the wellbore. Various methods have been developed and applied in the field to determine acid placement and the effectiveness of diversion process, but determining the injection profile during a course of matrix acidizing still remains as a challenge. Recently distributed temperature sensing technology (DTS) has enabled us to observe dynamic temperature profiles along a horizontal wellbore during acid treatments. Quantitative interpretation of dynamic temperature data can provide us with an invaluable tool to assess the effectiveness of the treatment as well as optimize the treatment through on-the-fly modification of the treatment parameters such as volume, injection rate and diversion method. In this study we first discuss how fluid placement can be quantified using dynamic temperature data. A mathematical model has been developed to simulate the temperature behavior along horizontal wellbores during and shortly after acid treatments. This model couples a wellbore and a near-wellbore thermal model considering the effect of both mass and heat transfer between the wellbore and the formation. The model accounts for all significant thermal processes involved during a treatment, including heat of reaction, conduction, convection. Then a fast and reliable inversion procedure is used to interpret the acid distribution profiles from the measured temperature profiles. We extend the real-time monitoring and evaluation of the acid stimulation treatment in horizontal wells to calculate the evolving skin factor as a function of time and location along the wellbore. As the skin factor is a reflection of the injectivity, it will indicate directly if the acid stimulation is effective and if diversion is successful. The approach to monitor the evolving skin along the lateral is to use a proper pressure transient model to calculate skin factor by integrating the inversion results of the temperature data (acid injection profile) with either surface or bottomhole injection pressure. This method can help engineers to optimize an acid stimulation in the field.Item Simultaneous propagation of multiple fractures in a horizontal well(2013-08) Shin, Do H; Sharma, Mukul M.As the development of shale resources continue to accelerate in the United States, improving the effectiveness and the cost efficiency of hydraulic fracturing completion is becoming increasingly important. For such improvement, it is necessary to investigate the effects of various design parameters and in-situ conditions on the resulting fracture dimensions and propagation patterns. In this thesis, a 3D geomechanical model was built using ABAQUS Standard to simulate the propagation of multiple competing fractures in a single fracture stage of a horizontal well. The reservoir was modeled as a porous elastic medium using C3D8RP pore pressure & stress elements. In addition, a vertical plane of COH3D8P pore pressure cohesive elements was inserted at each perforation cluster to model fracture propagation. Also, the flow distribution among perforation clusters was simulated using a parallel resistors model. The results suggested that the fracture spacing has the dominant impact on the number of propagated fractures. Even when all other conditions were favorable to fracture propagation, small fracture spacing reduced the number of propagated fractures. Similarly, in a given fracture stage, decreasing the number of perforation clusters abated inter-fracture stress interference, and increased the number of propagated fractures. Higher injection fluid viscosity significantly increased the fracture widths and slightly decreased the fracture lengths, but did not have any impact on the number of propagated fractures. Also, higher injection rates led to longer and wider fractures, and increased the number of propagated fractures. Therefore, a high injection fluid viscosity and a high injection rate should be used to promote fracture propagation. Lastly, higher Young's modulus of the target formation led to increased stress interference, and the resulting fractures were shorter and narrower. Therefore, if the Young’s modulus of a target formation is high, a wider fracture spacing should be considered. Through this study, a 3D geomechanical model was successfully formulated to simulate the propagation of multiple competing fractures. In addition, the effects of various hydraulic fracturing design parameters and in-situ conditions on the resulting fracture dimensions and propagation patterns were demonstrated.Item Stress reorientation in low permeability reservoirs(2011-08) Roussel, Nicolas Patrick; Sharma, Mukul M.The acknowledgement of the existence of stress changes in the reservoir due to production from a propped-open fracture has resulted in the development of a new concept: oriented or altered-stress refracturing. By initiating a secondary fracture perpendicular to the initial fracture, refracturing makes it possible to access higher pressurized regions of the reservoir, thus improving the productivity of the well. The redistribution of stresses around a fractured vertical well has two sources: (a) opening of propped fracture (mechanical effects) and (b) production or injection of fluids in the reservoir (poroelastic effects). The coupling of both phenomena is numerically modeled to quantify the extent and timing of stress reorientation around fractured production wells. Guidelines and type-curves are established that allow an operator to choose the timing of the refracture operation in the life of the well, and evaluate the potential increase in well production after refracturing. The selection of candidate wells for refracturing is often very difficult based on the information available at the surface. We propose a systematic methodology, based on dimensionless groups, that allows a field engineer to evaluate a well's potential for refracturing from an analysis of field production data and other reservoir data commonly available. This analysis confirms the crucial role played by stress reorientation in the success of refracturing operations. Another topic of interest is the multi-stage fracturing of horizontal wells. The opening of a propped transverse fracture causes a reorientation of stresses in its neighborhood, which in turn affects the direction of propagation of subsequent fractures. This phenomenon, often referred to as stress shadowing, can negatively impact the efficiency of each fracturing stage. By calculating the trajectory of multiple transverse fractures, we offer some insight on the completion designs that will (a) minimize fracture spacing without compromising the efficiency of each fracturing stage and (b) effectively stimulate natural fractures in the vicinity of the created fracture. In addition, a novel detection method of mechanical interference between multiple transverse fractures is established, based on net fracturing pressure data measured in the field, to calculate the optimum fracture spacing for a specific well.Item The Method of Distributed Volumetric Sources for Forecasting the Transient and Pseudo-steady State Productivity of Multiple Transverse Fractures Intersected by a Horizontal Well(2011-02-22) Fan, DiangengThis work of well performance modeling is focused on solving problems of transient and pseudo-steady state fluid flow in a rectilinear closed boundaries reservoir. This model has been applied to predict and to optimize gas production from a horizontal well intercepted by multiple transverse fractures in a bounded reservoir, and it also provides well-testing solutions. The well performance model is designed to provide enhanced efficiency with the same reliability for pressure transient analysis, and well performance prediction, especially in complex well fracture configuration. The principle is to simplify the calculation of the pressure response to an instantaneous withdraw, which happens in other fractures, within a shorter computational time. This pressure response is substituted with the interaction between the two whole fractures. This method is validated through comparison to results of rigorous Distributed Volumetric Sources (DVS) method in simple symmetric fracture configuration, and to results of field production data for complex well/fracture configuration of a tight gas reservoir. The results show a good agreement in both ways. This model indicates the capability to handle the situations, such as: various well drainages, asymmetry of the fracture wings, and curved horizontal well. The advantage of this well performance model is to provide faster processing - reducing the computational time as the number of fractures increase. Also, this approach is able to be applied as an optimization and screening tool to obtain the best fracture configurations for reservoir development of economically marginal fields, in terms of the number and dimensions of fractures per well, also with external economic and operational constraints.