Tight Gas Condensate Reservoirs Research Articles

Liquid phase blockage in micro-nano capillary pores of tight condensate reservoirs

The development of tight condensate gas reservoirs faces complex formation damage mechanisms, seepage characteristics and hydrocarbon phase changes, which are common challenges for both tight gas reservoirs and condensate gas reservoirs. In the near-well area, the liquid phase blockage problem due to water phase retention formed by capillary spontaneous imbibition of invasive water and oil phase accumulation due to retrograde condensation precipitation has become a key obstacle to the efficient development of tight condensate gas reservoirs. Experiments were conducted to evaluate the damage of liquid phase blockage under different conditions near the wellbore area. The results show that when the liquid phase saturation in the near-wellbore area increased to 80.12%, the relative permeability of the gas phase decreased to 0. It is concluded that the mixed wettability of formation rocks, ultra-low water saturation, abundant hydrophilic clay minerals and high capillary resistance of micro-nano pores are the main causes for the easy adsorption and retention of liquid phase. Reduced pressure transmission capacity and irreversible formation damage induced by liquid-phase blockage are the two major controlling factors for the low liquid phase flowback rate. It is suggested that developing a flowback system based on the formation physical properties differentiation to control water phase invasion, and changing wettability or injecting thermochemical fluid to control condensate blocking are feasible methods to relieve liquid phase blockage damage in tight condensate reservoirs. Cited as: Wang, Y., Kang, Y., Wang, D., You, L., Chen, M., Yan, X. Liquid phase blockage in micro-nano capillary pores of tight condensate reservoirs. Capillarity, 2022, 5(1): 12-22. https://doi.org/10.46690/capi.2022.01.02

Injection of Nanofluids with Fluorosurfactant-Modified Nanoparticles Dispersed in a Flue Gas Stream at Very Low Concentration for Enhanced Oil Recovery (EOR) in Tight Gas–Condensate Reservoirs

The main objective of this work is to evaluate the effect of nanofluids formed by surface-modified nanoparticles with a fluorosurfactant dispersed in a flue gas stream at low concentrations as an e...

Ca-DTPMP nanoparticles-based nanofluids for the inhibition and remediation of formation damage due to CaCO3 scaling in tight gas-condensate reservoirs

The oil productivity of tight gas-condensate reservoirs can be affected by the precipitation/deposition of inorganic scales such calcium carbonate (CaCO3), which leads to a reduction mainly in permeability and porosity of the porous media. Therefore, the main objective of this study is to develop for the first time a nanofluid based on the interaction between active nanoparticles such as Ca-diethylenetriamine pentamethylene phosphonic (Ca-DTPMP) and remaining synthesis fluid (RSF) obtained from the synthesis process, to simultaneously inhibit and remove the formation damage due to the precipitation/deposition of CaCO3 scales. The synthesis of the Ca-DTPMP nanoparticles was performed varying the phosphonate concentration between 0.01 and 0.5 M. The obtained nanoparticles were characterized through N2 physisorption at −196 °C for obtaining the surface area (SBET), field emission scanning electron microscopy (FESEM), and dynamic light scattering (DLS) measurements. The mean nanoparticles size of the obtained materials ranged between 36 and 69 nm and was lower for the nanoparticles synthesized with a lower concentration of DTPMP. Nanofluids containing the synthesized nanoparticles of Ca-DTPMP were prepared with RSF solutions in deionized water as a carrier fluid for different Ca-DTPMP/RSF ratios of 10, 50, 200 and 500. The ability of the nanoparticles and nanofluids to inhibit the CaCO3 scaling was evaluated in batch-mode experiments at 70 °C by measuring changes in the calcium ion (Ca2 +) concentration in the solution. The nanofluid with better performance was that prepared with 50 mg/L of Ca-DTPMP/0.3 nanoparticles and a Ca-DTPMP/RSF ratio of 10, with an inhibition efficiency of 67%. Further, coreflooding tests were carried out using the nanofluid with better performance from the batch – mode experiments. Displacement tests were conducted under tight gas-condensate reservoir conditions at a temperature of 110 °C (230 °F) and confining and pore pressures of 34.47 MPa (5000 Psi) and 6.89 MPa (1000 Psi), respectively. Inhibition and remediation of CaCO3 scaling were evaluated. The nanofluid was soaked in the porous media for 8 h. Based on the results of the relative permeability and oil recovery curves, it is possible to conclude that the synthesized nanofluid promotes the inhibition and removal of the formation damage due to CaCO3 inorganic scales. The nanofluid injection leads to an increase of the oil permeability of 57% in comparison with the base system, suggesting that the nanofluid acts as inhibitor agent, as remediation treatment, and as stimulation product of oil wells. Also, the treatment showed a perdurability of more than 60 pore volumes and increasing of oil recovery of 4 and 24% regarding the base and the damaged systems, respectively.

Effects of Surface Acidity and Polarity of SiO2 Nanoparticles on the Foam Stabilization Applied to Natural Gas Flooding in Tight Gas-Condensate Reservoirs

Foams in the oil and gas industry have been used as divergent fluids to attenuate the fluid channeling in high-permeability zones. Commonly, foams are generated using a surfactant solution in high-permeability reservoirs, which exhibit stability problems. Therefore, the main objective of this study is to stabilize the foams by the addition of modified silica nanoparticles, varying the surface acidity and polarity for natural gas flooding in tight gas-condensated reservoirs. Four types of modified silica-based nanoparticles with varying surface acidity and polarity (coated with vacuum residue) were synthesized and evaluated using surfactant adsorption. The basic nanoparticles exhibited a greater adsorption capacity of the surfactant, reaching an adsorbed amount of approximately 200 mg of surfactant per gram of nanoparticles, and Type I adsorption behavior. Foams were generated and evaluated based on their stability using two routes, namely, (1) with mechanical agitation and (2) methane flooding, to determi...

Enhancing recovery and sensitivity studies in an unconventional tight gas condensate reservoir

The recovery factor from tight gas reservoirs is typically less than 15%, even with multistage hydraulic fracturing stimulation. Such low recovery is exacerbated in tight gas condensate reservoirs, where the depletion of gas leaves the valuable condensate behind. In this paper, three enhanced gas recovery (EGR) methods including produced gas injection, CO2 injection and water injection are investigated to increase the well productivity for a tight gas condensate reservoir in the Montney Formation, Canada. The production performance of the three EGR methods is compared and their economic feasibility is evaluated. Sensitivity analysis of the key factors such as primary production duration, bottom-hole pressures, and fracture conductivity is conducted and their effects on the well production performance are analyzed. Results show that, compared with the simple depletion method, both the cumulative gas and condensate production increase with fluids injected. Produced gas injection leads to both a higher gas and condensate production compared with those of the CO2 injection, while waterflooding suffers from injection difficulty and the corresponding low sweep efficiency. Meanwhile, the injection cost is lower for the produced gas injection due to the on-site available gas source and minimal transport costs, gaining more economic benefits than the other EGR methods.

Interaction of anionic surfactant-nanoparticles for gas - Wettability alteration of sandstone in tight gas-condensate reservoirs

One of the most common sources of formation damage in tight reservoirs of gas-condensate is condensate banking. The condensate level on the porous media reduces the effective permeability to gas, decreasing the gas production primarily because the pressure reaches values that are lower than dew point pressure or because there is a sharp pressure drop in the near wellbore. The primary objective of this study is to develop a nanofluid, based on the interaction between an anionic surfactant and silica (SiO2) nanoparticles, to alter the reservoir wettability from a liquid-wet state to gas-wettability. The SiO2 nanoparticles were modified by an incipient method using a solution of anionic commercial surfactant Silnyl®FSJ (SY) at various concentrations from 3.0 to 7.0 wt%. Posteriorly, the nanofluids were prepared with modified SiO2 nanoparticles that were dispersed in an SY solution in deionized water. Nanofluids were initially evaluated at room conditions by contact angle and imbibition tests on oil-wet and water-wet sandstone samples for the wettability alteration to obtain the best concentration ratio of modified nanoparticles and SY in the nanofluid. Different combinations and individual effects of the nanoparticles and SY surfactant were evaluated. Better performance in changing the wettability of the system was achieved for a nanofluid at a concentration of 500 mg/L of SiO2 nanoparticles, which were functionalized with 5.0 wt% of SY and dispersed in an SY solution at 0.46 wt% in deionized water. In water-wet samples, contact angles changed from 0° to 118° and from 32° to 95° for water/rock/air and oil/rock/air systems, respectively. Similarly, for oil-wet samples, the contact angles were modified from 123° to 115° and from 0° to 93°.Coreflooding tests were performed under tight gas-condensate reservoir temperature and pressure conditions. Through the permeability curves and oil recovery, the synthesized nanofluid was observed to alter the wettability of the system from a strongly liquid-wet to a gas-wet condition. Additionally, according to the results, the use of the synthesized nanofluids can reduce the formation damage caused by the condensate banking, favoring the mobility of liquid and leading to a considerable improvement in oil and gas production. The oil recovery increases from 46.6% in the base system to 78.4% after treatment. Additionally, residual saturation of oil was reduced from 29.2% to 17.8% in the base and treated systems, respectively.

Reservoir and fluid characterization of a tight gas condensate well in the Montney Formation using recombination of separator samples and black oil history matching

Liquid-rich shale (LRS) reservoirs are economically attractive but operationally challenging particularly for cases where multi-phase flow occurs within the reservoir. Proper treatment of PVT and rock properties, as well as rock-fluid interaction, in these unconventional reservoirs is central to providing improved short- and long-term oil and gas production forecasts. In the presence of limited surface sampling, the available analytical models often do not provide satisfactory results due to the uncertainty in the initial in-situ fluid system. In such situations, and particularly when there are many unknown parameters, numerical models are ideally suited, using a history matching framework, to assist with reservoir and fluid characterization.In this paper, production data from a multi-fractured horizontal well completed in a tight gas condensate reservoir in the Montney Formation in western Alberta, Canada is presented and analyzed using black oil numerical simulation. An assisted history-matching routine (i.e. Differential Evolution (DE) algorithm) is used in combination with black oil numerical simulations to characterize reservoir fluids and estimate reservoir and hydraulic fracture properties. The applicability of black oil numerical simulation for accurate prediction of the fluid model and well performance using numerous compositional numerical simulations and various fluid systems is first verified. The in-situ fluid is assumed to be a mixture of recombined separator samples with unknown oil-gas recombination ratio. The effect of time of sampling on the produced well stream composition is considered.Our results show that recombined separator sample mixtures collected early on during production of wells subjected to limited drawdown can successfully represent reservoir fluid properties with the exception of saturation pressure. In other words, the reservoir fluid PVT behavior can be predicted by recombination of an early initial separator fluid sample only by varying the saturation pressure. Hence, the assisted history matching can be performed using black oil numerical simulations with a reduced number of unknowns for the fluid system. The well/reservoir properties and unknown reservoir fluid are characterized in terms of a 12-parameter system. The history-matched results using DE could satisfactorily reproduce the water and hydrocarbon surface flow rates, and flowing bottomhole pressure curves. The quality of results are comparable to those obtained previously (Hamdi et al., 2015) using a fully-compositional numerical model.The new workflow using assisted history-matching combined with black oil simulation provides a practical yet accurate method for characterizing fluid, reservoir and fracture properties in unconventional gas condensate systems.

Effect of nanoparticle inclusion in fracturing fluids applied to tight gas-condensate reservoirs: Reduction of Methanol loading and the associated formation damage

Hydraulic fracturing is one of the most common stimulation operations for increasing the productivity of a well. The fracturing fluid is one of the key factors in the operation and must accomplish some special requirements and behavior. The fluid that remains inside the fracture and the reservoir after the fracturing operation is finished, causes severe damage to the proppant pack and the formation, leading to a lower efficiency of the stimulation. This study presents experimental research on adding nanoparticles to a commercial fracturing fluid commonly used for tight gas-condensate reservoirs, aiming to enhance its performance in rheological behavior and its capacity to reduce the formation damage associated with the use of fracturing fluids. Nanoparticles with mean particle sizes of 8 and 19 nm with basic and acidic surface modifications were employed for modifying a commercial fracturing fluid. Rheology tests were performed at pressure and temperature conditions of 1.38 MPa and 104 °C, respectively, for the different nanoparticles at dosages of 100 and 200 mg/L. The improvement of those properties enabled the modification of the original formulation of the fluid, reducing the amount of methanol, one of most expensive and hazardous additives, by up to 33%, and reducing the formation damage by approximately 71%. Furthermore, this modified fluid was evaluated in terms of its impact in the wettability of the rock and its relative permeability to water and oil through static (contact angle measurements) and dynamic tests (relative permeability curves). The modified fracturing fluid showed an excellent capability to improve the water-wettability of the rock and also decreased the relative water permeability by 83%. This work demonstrates the suitability of adding nanoparticles to fracturing fluid for stimulations where it is necessary to reduce the relative permeability of water, acting as a Relative Permeability Modifier (RPM) in a conformance for a fracturing operation.

Technical Considerations for Optimizing Development Strategy in a Tight Gas Condensate Reservoir

Technical Considerations for Optimizing Development Strategy in a Tight Gas Condensate Reservoir

History Matching and Forecasting Tight Gas Condensate and Oil Wells by Use of an Approximate Semianalytical Model Derived From the Dynamic-Drainage-Area Concept

SummaryRecently, low-permeability (tight) gas condensate and oil reservoirs have been the focus of exploitation by operators in North America. Multifractured horizontal wells (MFHWs) producing from these reservoirs commonly exhibit long periods of transient flow, during which two-phase flow of oil and gas begins because of well flowing pressures dropping to less than saturation pressure. History matching and forecasting of such wells can be rigorously performed by use of numerical simulation, but this approach requires significant data and time to set up. Analytical methods, although requiring fewer data and less time to apply, have historically been developed only for single-phase-flow scenarios. In this work, a novel and rigorous analytical method is developed for history matching and forecasting MFHWs experiencing multiphase flow during the transient and boundary-dominated flow periods.The distance-of-investigation (DOI) concept has been used for many years in pressure-transient analysis to estimate distances of reservoir boundaries to wells, among other applications. In the current work, the DOI concept is used to estimate dynamic drainage area (DDA) to forecast tight gas condensate and oil wells; a linear flow geometry is assumed. During transient flow, the DDA is calculated at each timestep by use of the linear-flow DOI formulation; a multiphase version of the linear-flow productivity-index (PI) equation and material-balance equations for gas, condensate, and oil are solved iteratively for pressure, saturation, and fluid-production rate. The PI equations for gas and oil use pseudopressure, which is evaluated with saturation/pressure relationships derived from pressure/volume/temperature data. For boundary-dominated flow, when the drainage area is static, the inflow equations are again coupled with material balance for both phases.The new method is validated against numerical simulation, covering a wide range of fluid properties and operating conditions. The new method matches the simulation acceptably for all cases studied. Field examples of MFHWs are also analyzed to demonstrate the practical applicability of the approach. The three liquid-rich shale examples analyzed were also chosen to represent a wide range of fluid properties. In all cases, acceptable history matches are achieved.The new analytical forecasting/history-matching procedure developed in this work provides a practical alternative to numerical simulation for tight gas condensate and oil experiencing two-phase flow during the transient-flow period. The method, which does not rely on Laplace-space solutions, is conceptually simple to understand, easy to implement, and avoids the inconvenience of Laplace-space inversion.

Transient flow analysis and partial water relative permeability curve derivation for low permeability undersaturated coalbed methane wells

Rate transient analysis (RTA) is an important reservoir engineering tool used to extract reservoir and stimulation information from flow rates and pressures obtained from producing wells. Adaptation of analytical RTA methods for this purpose has been slow for coalbed methane (CBM) reservoirs because of the complexities of multi-phase flow, non-static absolute permeability, desorption, among others. Some progress has been made historically for high permeability CBM reservoirs, where depletion (boundary-dominated flow) occurs quickly, however low permeability CBM reservoirs are currently being evaluated internationally (e.g. China), which brings forward additional challenges. For example, in some instances, low permeability, undersaturated CBM wells exhibit long periods of transient flow, during which the transition from single-phase flow of water to two-phase flow of gas and water occurs. This behavior has not been dealt with rigorously in the development of analytical RTA methods. It is the purpose of the current work to extend RTA to apply to low-permeability, undersaturated CBM wells exhibiting this behavior.The horizontal CBM well studied in this work exhibits two periods of apparent transient linear flow separated by a transition, as determined from diagnostic analysis of water production data using a log–log plot of rate-normalized pressure (RNP) versus time. It is hypothesized that the well actually exhibits transient linear flow throughout the entire studied production period (supported by reservoir simulation) and that productivity changes leading to the apparent transition in flow regime are caused by the combined effects of relative permeability changes after desorption pressure is reached, and (possibly) fines migration and stress-dependent permeability. In order to extend the early single-phase linear flow analysis of this well (occurring above desorption pressure) to the multi-phase period (below desorption pressure), the RNP half-slope trend (linear flow) established during the single-phase flow period is extrapolated through the rest of the production period. An RNP ratio (RNPR) is then created by calculating the ratio of the extrapolated (corrected) RNP and the RNP of the uncorrected field data. The RNPR can then serve to correct the production data affected by multi-phase flow (and possibly fines migration and stress dependent permeability) and hence extend the amount of data that can be used for production analysis. Further, the RNPR squared, combined with water saturation calculations, may be used to derive water relative permeability curves from the transient data. These concepts are tested using both numerical simulation and field data. The resulting field-derived water relative permeability curve can be used as a solid starting point for simulation history-matching, although it covers a limited range of water saturations.This work should be of interest to professional engineers and geoscientists involved in CBM reservoir characterization efforts. Future work will determine if these concepts are applicable to other low-permeability reservoirs exhibiting the transition from single- to multi-phase flow during the transient linear flow period, such as tight oil and gas condensate reservoirs.

Using differential evolution for compositional history-matching of a tight gas condensate well in the Montney Formation in western Canada

Production data analysis for low-permeability unconventional reservoirs is a challenging task, particularly for cases where multi-phase flow occurs within the reservoir. Analytical models developed to account for multi-phase flow typically require calculation of pseudo variables, which in turn require knowledge of relative permeability and fluid data. In the presence of sparse sampling, the analytical models often do not provide satisfactory results when there are so many unknown parameters. In such situations, numerical models are better suited, using a history matching framework to assist with reservoir and fluid characterization.In this work, we implement an assisted history-matching routine to characterize reservoir fluids and extract reservoir and hydraulic fracture properties for a hydraulically-fractured horizontal well completed in a tight gas condensate reservoir within the Montney Formation in western Alberta, Canada. The initial water distribution (e.g. movable water profile in the reservoir), in situ fluid (e.g. initial hydrocarbon composition with C7+ properties) and reservoir properties (e.g. permeability in the matrix and around the fracture, and pressure dependent fracture permeability) are described in terms of 20 unknown parameters, which creates a high-dimensional inverse problem. We use the Differential Evolution algorithm, which is a powerful population-based optimization algorithm, and employ numerical compositional simulations to match pressure, water and hydrocarbon rates, and surface compositions of the produced fluids. Application of this optimization routine results in a good match to all measured data. The DE algorithm is repeated for an extra run to check for the existence of other non-unique solutions. The history-match results helped determine parameters for well/reservoir description and develop a compositional fluid model based on the measured separator composition data. The collected samples for both DE runs, along with one thousand extra samples from quasi-random sequence sampling design, provide a pool of data with invaluable information that are used to perform the global sensitivity analysis and to rank the contribution of each descriptive parameter on the variances of the reservoir outputs. In this way, the value of production data and surface compositions for the characterization of reservoir and fluid is quantified.This work aims to provide a practical and simple workflow for analysis of unconventional reservoirs where the direct analytical approaches cannot be applied.

Energy Control in the Depletion of Gas Condensate Reservoirs with Different Permeabilities

Energy control (i. e. pressure control) has an obvious effect on development effect in the depletion of gas condensate reservoir. Phase change behavior and characteristics of the relative pemeability in gas condensate reservoirs were displayed in this paper, then pressure and condensate distribution were showed through reservoir simulation. Finally, the influence of the pressure drop on condensate distribution and condensate oil production in gas condensate reservoirs with different permeabilities was studied. Results show that: First, in high / moderate permeability gas condensate reservoirs, the pressure and the condensate blocking will extend to further reservoir, while the pressure and condensate just appear in the vicinity of wellbore in low permeability gas condensate reservoirs. Second, the influence of pressure drop on condensate distribution in high permeability gas condensate reservoirs is obvious, the condensate blocking extends with the increasing of the pressure drop, and condensate extent can be controlled by optimizing a rational pressure drop, while the influence is inconspicuous in low permeability gas condensate reservoirs. Third, the influence of pressure drop on condensate oil production in high / moderate permeability gas condensate reservoirs is conspicuous, a rational pressure drop exists, while the influence is indistinct in low permeability or tight gas condensate reservoirs, before the retrograde condensation, a low pressure drop should be adopted in a long term until the bottom hole flowing pressure drops below the dew point pressure, when the condensate blocking forms, well stimulation is advised before developing by pressure control.

Investigation on the Importance of the Diffusion Process During Lean Gas Injection Into a Simple Synthetic Depleted Naturally Fractured Gas Condensate Reservoir

A depleted naturally fractured gas condensate reservoir with extremely tight matrix permeability in the center of Iran is used for gas storage. Due to the tightness of the matrix, simulation of this process may present a unique challenge in terms of the importance of diffusion process in flow behavior of the injected gas in matrix blocks. This article presents a multimechanistic (Darcian-type flow and Fickian-type flow) mathematical model to investigate the importance of diffusion process as a function of important rock and fluid parameters. The authors' approach consists of the following steps: (a) development of a 1-D governing equations for a single matrix block consists of a gas condensate mixture considering multimechanistic approach and (b) numerical solution of the highly nonlinear governing equations using Newton-Raphson technique in conjunction with Broyden updating approach. The model developed is validated against an analytical model applying the simplifying assumptions behind the analytical model. To investigate the importance the diffusion process a sensitivity study is done using typical values of rock and fluid properties for a tight gas condensate reservoir. In general, the results show that the diffusion is an effective process at permeabilities less than about 0.01 md and ignoring this process may create a drastic error in performance prediction of the reservoir.

Gas Condensate Flow Around Hydraulically Fractured Wells

Fracturing is one of the most common well-stimulation techniques especially for tight gas-condensate reservoirs. Considerable efforts have been devoted to this subject albeit mainly for single-phase or conventional gas oil systems. Gas condensate flow around hydraulically fractured wells (HFWs) is different from that in conventional gas oil systems. Previous studies (Danesh et al. in Gas Condensate Recovery Studies, 1994; Jamiolahmady in Transp Porous Media 41(1): 17–46, 2000) have shown that at low to moderate velocities, the relative permeability of these low interfacial tension systems increases as velocity increases and/or interfacial tension decreases. At very high velocity values, on the other hand, the inertial effect becomes dominant, reducing the relative permeability as velocity increases (Forchheimer in Hydraulik, Chap 15, Teubner, Leipzik, 1914). Description of HFWs in gas condensate reservoirs using the existing reservoir simulators requires the use of very fine grids to capture the abrupt changes in flow and rock parameters for these systems. This task is very cumbersome, time consuming and impractical. In this work, a two-dimensional mathematical simulator has been developed, based on finite-difference methods. The simulator accounts for phase change, condensate drop out, coupling and inertial effects. This single-well model has been used to investigate the impact of important geometrical and flow parameters on the performance of a HFW. Based on this investigation new formulae have been developed for fracture skin factor and effective wellbore radius. The developed formula for effective wellbore radius, which is applicable under both steady state and pseudo-steady state conditions, can be used in an equivalent open-hole system replicating flow around HFWs. The approach is similar to that followed for single phase systems albeit with a modified formula for the fracture conductivity term as developed here. Another important application of these formulae is in the optimization of fracture dimensions for a given fracture volume, in gas condensate reservoirs.

Productivity evaluation of hydraulically fractured gas-condensate reservoirs

This study describes an application of a compositional single well simulator to analyse well tests in gas-condensate reservoirs. An important aspect of this application for gas-condensate well tests is accurate fluid property prediction during the multi-phase flow regime, which occurs in the near-well region. The simulator can also be used to understand the impact of liquid drop-out and fracture flow on well productivity. Hydraulic fracturing improves the economics of wells drilled in tight reservoirs. However, the operation involves a significant amount of expenditure. In recent years this technique has also been used to stimulate gas-condensate reservoirs by creating a flow conduit through the condensate banking near the well. Thus, it is crucial to keep a fracture as small as possible. In practice it has been proved that a short, wide fracture can provide much higher production than the traditionally pursued narrow, long fracture. The workflow in this study contains compositional simulation of a single well in a tight gas-condensate reservoir, which is used to generate transient pressure data for well test analysis and interpretation to predict multi-phase flow behaviour, and to analyse productivity impairment due to condensation. Simulation models were then further modified to study the impact of various hydraulic fractures on the well productivity index (PI), which is defined as the ratio of production rate (constant) divided by the pressure drop across the reservoir. PIs for fractured cases are compared with respect to the non-fractured base case. Streamline simulation of the fractured gas-condensate reservoir was also included in the study to allow visualization of the flow profile in and around the hydraulic fracture.