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Hydraulically fractured tight gas reservoirs are one of the most common unconventional gas sources being produced today, and will be a regular source of gas in the future. The extremely low permeability of tight gas sands leads to inaccuracy of conventional build-up and draw-down well test results. This is primarily due to the increased time required for transient flow in tight gas sands to reach pseudo-steady state condition. To increase accuracy, well tests for tight gas reservoirs must be run for longer periods of time which is in most cases not economically viable. The large amount of downtime required to conduct well tests in tight sands makes them far less economical than conventional reservoirs, which leads to the need for accurate simulation of tight gas reservoir well tests. This paper presents simulation results of a 3-D hydraulically fractured tight gas model created using Eclipse software. The key aims are to analyze the effect of differing fracture orientation, number and length. The focus of the simulation runs will be on the effect of hydraulic fracture orientation and length. The results will be compared to simulation runs without the abovementioned factors to determine their effects on production rates and well performance analysis. All results are plotted alongside an un-fractured tight gas scenario in order to put the hydraulic fracture performance in perspective. Key findings from this work include an approximately linear relationship between initial gas rate and the number of hydraulic fractures intersecting the wellbore. In addition, fracture length is found to have less of an impact on initial gas rate compared to number of fractures intersecting the wellbore, for comparable total fracture volumes.

Tight gas reservoirs normally have production problems due to very low matrix permeability and different damage mechanisms during drilling, completion and stimulation operations. Therefore they may not produce gas at commercial rates without production optimization and advanced completion techniques. Tight formations have small pore throat size with significant capillary pressure energy suction that imbibes and holds liquid in the capillary pores. Leak-off of liquid from the wellbore into the formation may damage near wellbore permeability due to water blocking damage and clay swelling, and it can significantly reduce well productivity even in hydraulically fractured tight gas reservoirs. This study presents evaluation of damage mechanisms associated with water invasion and phase trapping in tight gas reservoirs. Single well reservoir simulation is performed based on typical West Australian tight gas formation data, in order to understand how water invasion into the formation affects well production performance in both non-fractured and hydraulically fractured tight gas reservoirs. A field example of hydraulic fracturing in a West Australian tight gas reservoir is shown and the results are analyzed in order to show importance of damage control in hydraulic fracturing stimulation of low permeability sand formations. The study results highlight that water blacking can be a major damage mechanism in tight gas reservoirs. In water sensitive tight sand formations, damage control is essential and the well productivity improvement may not be achieved in the case of excessive water leak-off into formation during hydraulic fracturing operations.

The low permeability and tight gas reservoirs are problematic throughout of their development (drilling, completion, stimulation and production) around the wellbore. However, they required advanced improvement techniques to achieve flow gas at optimum rates. Phase Trapping or retention of fluids is a form of mechanical formation damage mechanism, which is caused by fluid invasion into formation, and also when liquid leak-off into formation during fracturing stimulation near the wellbore. Low permeability and tight gas reservoir are sensitive to water invasion damage results create water blocking and phase trapping damage due to high critical water saturation, relative permeability effects, capillary pressure and Interfacial tension between produced fluid and wellbore fluid. Proper evaluation of damage and its factors which influenced its severity is essential for prevention and optimizing well productivity. Thus, this study is presenting both laboratory experiments and simulation to evaluate phase trapping damage. In which, the core flooding was performed to evaluate permeability damage by using Malaysian diesel-oil drilling fluid in comparison with water based drilling fluid. Further, interfacial tension was tested between produced gas and wellbore fluids at different temperature and pressure conditions. The effect of interfacial tension on phase trapping damage was observed and validate with the result of core flooding experiments where the affect of water injection and diesel-oil injection on core permeability was studied and shown. Reservoir Simulation approach was also used to study the effect of relative permeability curves on phase trapping damage and its impact on well productivity. The result highlights the benefits of using Malaysian diesel-oil in drilling and fracturing the low permeability and tight gas reservoirs in meaning of 30% increment in well productivity compared with water based fluid.

Welltest interpretation requires diagnosis of reservoir flow regimes to determine the basic reservoir characteristics. In hydraulically fractured unconventional oil and reservoirs, the reservoir flow regimes may not clearly be revealed on diagnostic plots of transient pressure and its derivative due to extensive wellbore storage effect, fracture characteristics, and also heterogeneity and complexity of reservoir. Thus, use of conventional welltest analysis in interpreting the limited acquired data may fail to provide reliable results, causing erroneous outcomes. To overcome such issues, transient analysis techniques that utilize higher order pressure derivatives integrated with rate transient analysis (RTA) can reduce uncertainties associated with welltest analysis and provide better estimate of the reservoir and hydraulic fractures dynamic parameters. This paper illustrates the reservoir flow regimes in non-fractured and hydraulically fractured unconventional reservoirs, proposes welltesting and interpretation methodologies, and presents field examples in order to show how the hydraulic fracture size and the permeability of the stimulated reservoir volume can estimated for hydraulically fractured unconventional gas reservoirs.

Low matrix permeability and significant damage mechanisms are the main signatures of tight gas reservoirs. During drilling and fracturing of tight formations, the wellbore liquid invades the tight formation, increases liquid saturation around wellbore and eventually reduces permeability at near wellbore. The liquid invasion damage is mainly controlled by capillary pressure and relative permeability curves. Water blocking and phase trapping damage is one of the main concerns in use of water based drilling fluid in tight gas reservoirs, since due to high critical water saturation, relative permeability effects and strong capillary pressure, tight formations are sensitive to water invasion damage. Therefore, use of oil based mud may be preferred in drilling or fracturing of tight formation. However invasion of oil filtrate into tight formations may result in introduction of an immiscible liquid hydrocarbon drilling or completion fluid around wellbore, causing entrapment of an additional third phase in the porous media that would exacerbate formation damage effects. This study focuses on phase trapping damage caused by liquid invasion using water-based drilling fluid in comparison with use of oil-based drilling fluid in water sensitive tight gas sand reservoirs. Reservoir simulation approach is used to study the effect of relative permeability curves on phase trap damage, and results of laboratory experiments core flooding tests in a West Australian tight gas reservoir are shown in which the effect of water injection and oil injection on the damage of core permeability are studied. The results highlights benefits of using oil-based fluids in drilling and fracturing of tight gas reservoirs in term of reducing skin factor and improving well productivity.

Wireline formation testing and measurement of true formation pressure can provide essential knowledge about the reservoir dynamic characteristics. In tight formations, a reliable determination of pressure and mobility gradients is challenging because of the tight nature of formation rock. Due to the very low reservoir permeability, the mud cake across wellbore is often ineffective in preventing filtrate invasion, thus causing the measured pressure to be higher than actual formation pressure as a result of supercharging effect. Wireline formation testing measurements are also influenced by the effects of filtrate invasion and capillary pressure, as the measured pressure is pressure of drilling fluid filtrate, the continuous phase present in the invaded region around wellbore. As a result, the measured pressure might be different to true formation pressure. This effect is more noticeable in tight gas reservoirs due to capillary pressure effect.This paper looks into estimation of true formation pressure and evaluates the effect of filtrate invasion damage and supercharging on wireline formation tester measurements in tight gas reservoirs. Numerical simulation approach is used to build the reservoir model based on data acquired from a tight gas reservoir. The model undergoes water injection followed by gas production from different testing points along the wellbore, and the corresponding pressure gradients are plotted to check for pressure matching with that of the formation fluid in the virgin region. The results indicate the significant effects of supercharging, reservoir characteristics, capillary pressure and liquid invasion damage on wireline formation pressure measurements in tight gas reservoirs.

Tight gas reservoirs are mainly characterized by low matrix permeability and significant damage. During drilling and fracturing of tight formations, wellbore liquid invades into tight formation and increases water saturation around wellbore and eventually reduces permeability near wellbore or adjacent to fracture wings. The damage to permeability caused by invasion of liquid into tight formation is controlled by capillary pressure and relative permeability curves. The phase trap damage is one of the main concerns in use of water based drilling or fracturing fluid, since due to high critical water saturation, strong capillary pressure, and sensitivity of tight sand to water. Therefore, use of oil based mud may be preferred in drilling or fracturing of tight formation. However invasion of oil filtrate into tight formation may result in a three-phase relative permeability curves in invaded zone in presence of reservoir gas and initial water, which may differently affect damage and productivity of tight gas reservoirs. This study evaluates phase trap damage in water-based in comparison with oil-based drilled or fractured tight gas reservoir. Reservoir simulation is used to study the effect of relative permeability curves on phase trap damage and well productivity, based on reservoir and core data from a West Australian tight gas reservoir. The results highlights benefits of using oil-based fluids in drilling and fracturing of tight gas reservoirs in term of improving well productivity.

Tight gas reservoirs normally have production problems due to very low matrix permeability and significant damage during well drilling, completion, stimulation and production. Therefore, they might not flow gas at optimum rates without advanced production improvement techniques. The main damage mechanisms and the factors that have significant influence on total skin factor in tight gas reservoirs include mechanical damage to formation rock, water blocking, relative permeability reduction around wellbore as a result of filtrate invasion and liquid leak-off into the formation during fracturing operations. Drilling and fracturing fluids invasion mostly occurs through permeable zones or natural fractures and might also lead to serious permeability reduction in the rock matrix that surrounds the wellbore, natural fractures, or hydraulic fracture wings. This study represents evaluation of water blocking damage in tight gas formations, and the influence on core flow efficiency and well productivity. Core scale reservoir simulations were carried out based on a typical Western Australia tight gas reservoir in order to numerically model liquid invasion during overbalanced, balanced and underbalanced drilling, and the effect on gas production in clean-up period. The simulation results describe how water blocking reduces near wellbore permeability and affects well productivity and gas recovery from tight gas reservoirs.

Tight gas reservoirs normally have production problems due to very low matrix permeability and different damage mechanisms during drilling, completion and stimulation. Tight reservoirs need advanced drilling and completion techniques to efficiently connect wellbore to the formation open natural fractures and produce gas at commercial rates. Stress regimes have significant influence on tight gas reservoirs production performance. The stress regimes cause wellbore instability issues while drilling, which can result in large wellbore breakouts. The stress regimes can also control the well long-term production performance, since they affect permeability anisotropy. The preferred horizontal flow direction is expected to be parallel to the maximum in situ horizontal stress. The production and welltest data in non-fractured as well as hydraulically fractured wells in tight reservoirs have indicated the presence of a long-term linear flow regime due to the well and reservoir geometry and also as a result of the permeability anisotropy. The stress anisotropy leads to different permeabilities in different directions, and the natural fractures that are aligned with maximum horizontal stress; they might have larger aperture and greater permeability. Due to the more severe stress anisotropy in tight formations, permeability in maximum stress direction might significantly be larger than permeability in the direction of minimum stress. This study represents evaluation of parameters that might control well productivity and long-term well production performance in tight gas reservoirs. Geomechanical modeling is performed in order to understand the effect of stress anisotropy on aperture evolution of natural fractures in different directions. Furthermore, single well reservoir simulation study is performed in order to generate pressure build-up data for a typical tight gas reservoir, in order to evaluate effect of reservoir geometry and permeability anisotropy on late time linear flow regime, and also assess the well production performance for different well and reservoir conditions.

Welltest interpretation requires diagnosis of reservoir flow regimes in order to determine the basic reservoir characteristics such as average reservoir permeability and skin factor. Due to wellbore storage effect, wellbore phenomena and complexity of reservoir response from heterogeneous reservoir layers, detection of the reservoir flow regimes using standard welltest diagnostic plots might be challenging and have some uncertainties. In pressure transient testing, there are instances where the flow regimes might not clearly be revealed on diagnostic plots of pressure build-up and its derivative, such as incomplete pressure build-up tests, low permeability reservoirs and multi-phase producing wells. In such cases, the Semi-Log plot of first and second derivative of transient pressure versus time can be used to reduce the uncertainties associated with welltest analysis. This paper describes a new method for well test interpretation using second derivative of transient pressure. Two field examples are shown in which a reliable radial flow regime on pressure build-up data could not be detected using standard plots. The second derivative approach was used to predict radial flow regime trend and estimate the reservoir permeability and skin factor, which the results were in good agreement with production data in these wells.

Abstract Interpretation of temperature logs has been done successfully in wells to identify water or gas entries location, detect casing leaks, and evaluate cement placement. This paper shows how knowledge of the Joule-Thomson cooling effect and frictional heating effect can be applied for well test interpretation. Many analysts rely on pressure derivative curve to diagnose wellbore storage period and radial flow regime on pressure transient data. However, there are field examples that flow regimes can't be accurately determined. During transient tests, both pressure and temperature are changed depending on downhole flow rate. In gas producing wells, Joule-Thomson cooling and frictional heating effects are the main dynamic factors causing flowing bottomhole temperature to differ from the static formation temperature at that depth. When a gas well is shut in, JT cooling effect is vanished and this causes a sharp increase in sandface temperature. As effect of WBS ends, wellbore temperature gradually cools down due to heat conduction with near wellbore region. This paper demonstrates a new technique for determining end of wellbore storage in pressure build-up tests for gas producing wells using temperature transient data. Application of this robust technique was demonstrated using three gas wells in which both temperature and pressure transient data were analyzed for more accurate welltest interpretation. Introduction In pressure transient tests [1], the early portion of the well test data is usually affected by the wellbore storage effect and might be influenced by skin[2] and reservoir permeability. The wellbore storage effect delays the formation pressure response and distorts the early portion of pressure transient data. Diagnosing of the radial-flow regime is crucial to quantitative interpretation since it provides values for permeability and skin. Unit slope and the plateau on the pressure derivative curve as well as Horner plot are usually used to identify pure wellbore storage and radial flow regime as shown in Fig.1. The interpreter's first task always is to identify the unit slope line and derivative plateau to identify flow regimes [3].

Tight gas reservoirs incur problems and significant damage caused by low permeability during drilling, completion, stimulation and production. They require advanced improvement techniques to achieve flow gas at optimum rates. Water blocking damage (phase Trapping/retention of fluids) is a form of mechanical formation damage mechanism, which is caused by filtrate invasion in drilling operations mostly in fracturing. Water blocking has a noticeable impact on formation damage in gas reservoirs which tends to decrease relative permeability near the wellbore. Proper evaluation of damage and the factors which influence its severity is essential to optimize well productivity. Reliable data regarding interfacial tension between gas and water is required in order to minimize mechanical formation damage potential and to optimize gas production. This study was based on the laboratory experiments of interfacial tension by rising drop method between gas-brine, gas-condensate and gas-brine. The results showed gas condensate has low interfacial tension value 6 – 11 dynes/cm when compared to gas-brine and gas- diesel which were 44 – 58 dynes/cm and 14 – 19 dynes/cm respectively. In this way, the capillary pressure of brine-gas system was estimated as 0.488 psi, therefore diesel-gas system was noticed about 0.164 psi and 0.098 psi for condensate-gas system. A forecast model was used by using IFT values to predict the phase trapping which shows less severe phase trapping damage in case of condensate than diesel and brine. A reservoir simulation study was also carried out in order to better understand the effect of hysteresis on well productivity and flow efficiency affected due to water blocking damage in tight gas reservoirs.

Tight-gas reservoirs have low permeability and significant damage. When drilling the tight formations, wellbore liquid invades the formation and increases water saturation of the near wellbore area and significantly deceases permeability of this area. Because of the invasion, the permeability of the invasion zone near the wellbore in tight-gas formations significantly decreases. This damage is mainly controlled by wettability and capillary pressure (Pc). One of the methods to improve productivity of tight-gas reservoirs is to reduce IFT between formation gas and invaded water to remove phase trapping. The invasion of wellbore liquid into tight formations can damage permeability controlled by Pc and relative permeability curves. In the case of drilling by using a water-based mud, tight formations are sensitive to the invasion damage due to the high-critical water saturation and capillary pressures. Reducing the Pc is an effective way to increase the well productivity. Using the IFT reducers, Pc effect is reduced and trapped phase can be recovered; therefore, productivity of the TGS reservoirs can be increased significantly. This study focuses on reducing phase-trapping damage in tight reservoirs by using reservoir simulation to examine the methods, such use of IFT reducers in water-based-drilled tight formations that can reduce Pc effect. The Pc and relative permeability curves are corrected based on the reduced IFT; they are then input to the reservoir simulation model to quantitatively understand how IFT reducers can help improve productivity of tight reservoirs.

With the reduction of conventional reserves, the demand and exploration of unconventional sources becomes increasingly important in the energy supply system. Low permeability, low porosity, and the complexities of rock formation in unconventional gas reservoirs make it difficult to extract commercially viable gas resources. Hydraulic fracture is the most common technique used for commercial production of hydrocarbon resources from unconventional tight-gas reservoirs. Due to the existence of an extremely long transient-flow period in tight-gas reservoirs, the interpretation of welltest data based on conventional welltest analysis is quite challenging, and could potentially lead to misleading results. This peer-reviewed paper presents a new approach based on a log-log reciprocal rate derivative plot. Emphases are given on the identification of factors affecting the welltest response in multiple hydraulic-fractured wells in unconventional gas reservoirs based on numerical simulation. The objective is to investigate the sensitivity of various reservoir and hydraulic-fracture parameters, such as multiple hydraulic-fracture size, fracture number and fracture orientation on welltest response, and the effect of the pressure derivative curve on the slopes of welltest diagnostic plots, as well as on well productivity performance. The results can be used to understand the welltest response for different hydraulic-fracturing scenarios for the efficiency and characteristics of hydraulic fractures.

Wireline formation testing and measurement of true formation pressure can provide essential knowledge about the reservoir dynamic characteristics. In tight formations, a reliable determination of pressure and mobility gradients is challenging because of the tight nature of formation rock. Due to the very low reservoir permeability, the mud cake across wellbore is often ineffective in preventing filtrate invasion, thus causing the measured pressure to be higher than actual formation pressure as a result of supercharging effect. Wireline formation testing measurements are also influenced by the effects of filtrate invasion and capillary pressure, as the measured pressure is pressure of drilling fluid filtrate, the continuous phase present in the invaded region around wellbore. As a result, the measured pressure might be different to true formation pressure. This effect is more noticeable in tight gas reservoirs due to capillary pressure effect. This paper looks into estimation of true formation pressure and evaluates the effect of filtrate invasion damage and supercharging on wireline formation tester measurements in tight gas reservoirs. Numerical simulation approach is used to build the reservoir model based on data acquired from a tight gas reservoir. The model undergoes water injection followed by gas production from different testing points along the wellbore, and the corresponding pressure gradients are plotted to check for pressure matching with that of the formation fluid in the virgin region. The results indicate the significant effects of supercharging, reservoir characteristics, capillary pressure and liquid invasion damage on wireline formation pressure measurements in tight gas reservoirs.

Low matrix permeability and significant damage mechanisms are the main signatures of tight-gas reservoirs. During the drilling and fracturing of tight formations, the wellbore liquid invades the tight formation, increases liquid saturation around the wellbore, and eventually reduces permeability at the near wellbore zone. The liquid invasion damage is mainly controlled by capillary pressure and relative permeability curves. Due to high critical water saturation, relative permeability effects and strong capillary pressure, tight formations are sensitive to water invasion damage, making water blocking and phase trapping damage two of the main concerns with using a water-based drilling fluid in tight-gas reservoirs.Therefore, the use of an oil-based mud may be preferred in the drilling or fracturing of a tight formation. Invasion of an oil filtrate into tight formations, however, may result in the introduction of an immiscible liquid-hydrocarbon drilling or completion fluid around the wellbore, causing the entrapment of an additional third phase in the porous media that would exacerbate formation damage effects. This study focuses on phase trapping damage caused by liquid invasion using a water-based drilling fluid in comparison with the use of an oil-based drilling fluid in water-sensitive, tight-gas sand reservoirs. Reservoir simulation approach is used to study the effect of relative permeability curves on phase trap damage, and the results of laboratory experiments of core flooding tests in a West Australian tight-gas reservoir are shown, where the effect of water injection and oil injection on the damage of core permeability are studied. The results highlight the benefits of using oil-based fluids in drilling and fracturing of tight-gas reservoirs in terms of reducing skin factor and improving well productivity.

Welltest interpretation requires the diagnosis of reservoir flow regimes to determine basic reservoir characteristics. In hydraulically fractured tight gas reservoirs, the reservoir flow regimes may not clearly be revealed on diagnostic plots of transient pressure and its derivative due to extensive wellbore storage effect, fracture characteristics, heterogeneity, and complexity of reservoir. Thus, the use of conventional welltest analysis in interpreting the limited acquired data may fail to provide reliable results, causing erroneous outcomes. To overcome such issues, the second derivative of transient pressure may help eliminate a number of uncertainties associated with welltest analysis and provide a better estimate of the reservoir dynamic parameters. This paper describes a new approach regarding welltest interpretation for hydraulically fractured tight gas reservoirs—using the second derivative of transient pressure. Reservoir simulations are run for several cases of non-fractured and hydraulically fractured wells to generate different type curves of pressure second derivative, and for use in welltest analysis. A field example from a Western Australian hydraulically fractured tight gas welltest analysis is shown, in which the radial flow regime could not be identified using standard pressure build-up diagnostic plots; therefore, it was not possible to have a reliable estimate of reservoir permeability. The proposed second derivative of pressure approach was used to predict the radial flow regime trend based on the generated type curves by reservoir simulation, to estimate the reservoir permeability and skin factor. Using this analysis approach, the permeability derived from the welltest was in good agreement with the average core permeability in the well, thus confirming the methodology’s reliability.

Water breakthrough and the flow of water towards the perforations of a producing well increase production operation costs and influence overall recovery efficiency. To control water production, a downhole water sink can be used in which a well is completed in both oil and water zones. Water is produced from an interval in water zone, which can result in the same pressure drop below water oil contact (WOC) as the pressure drop created by oil or gas production. This system can reduce water production through oil zone perforations. Water produced from water zone perforations can then be injected in deeper aquifers intervals. This technology can also be implemented in horizontal and multi-lateral wells to further increase hydrocarbon recovery with fewer water problems. This study examines the use of horizontal downhole water sink technology to increase oil recovery. Numerical simulation is performed to optimise oil production and water control in a multi-layered oil reservoir, by optimising the direction of drilling and the downhole water sink method. Different scenarios of drilling direction and horizontal down-hole water sink method are examined to identify the option that provides maximum oil recovery. The simulation results showed that drilling horizontal wells in a north–south direction resulted in higher well productivity, and that wells with significantly more water production problems can be controlled using a horizontal downhole water sink.

Tight gas reservoirs normally have production problems due to very low matrix permeability and significant damage during well drilling, completion, stimulation and production. Therefore, they may not flow gas at optimum rates without advanced production improvement techniques. The main damage mechanisms and the factors that have significant influence on total skin factor in tight gas reservoirs include: mechanical damage to formation rock; plugging of natural fractures by mud solid particle invasion; relative permeability reduction around wellbore as a result of filtrate invasion; liquid leak-off into the formation during fracturing operations; water blocking; skin due to wellbore breakouts; and the damage associated with perforation. Drilling and fracturing fluids invasion mostly occurs through natural fractures and may also lead to serious permeability reduction in the rock matrix that surrounds the natural or hydraulic fractures. This study represents an evaluation of different damage mechanisms in tight gas formations, and examines the factors that can have significant influence on total skin factor and well productivity. Reservoir simulation was carried out based on a typical West Australian tight gas reservoir to understand how well productivity is affected by each of the damage mechanisms, such as natural fracture plugging, mud filtrate invasion, water blocking and perforation. Furthermore, some damage prevention and productivity improvement techniques are proposed, which can help improve well productivity in tight gas reservoirs.

The increasing global demand for energy along with the reduction in conventional gas reserves has lead to the increasing demand and exploration of unconventional gas sources. Hydraulically-fractured tight gas reservoirs are one of the most common unconventional sources being produced today and look to be a regular source of gas in the future. Hydraulic fracture orientation and spacing are important factors in effective field drainage and gas recovery. This paper presents a 3D single well hydraulically fractured tight gas model created using commercial simulation software, which will be used to simulate gas production and synthetically generate welltest data. The hydraulic fractures will be simulated with varying sizes and different numbers of fractures intersecting the wellbore. The focus of the simulation runs will be on the effect of hydraulic fracture size and spacing on well productivity performance. The results obtained from the welltest simulations will be plotted and used to understand the impact on reservoir response under the different hydraulic fracturing scenarios. The outputs of the models can also be used to relate welltest response to the efficiency of hydraulic fractures and, therefore, productivity performance.

Tight gas reservoirs normally have production problems due to very low matrix permeability and significant damage during well drilling, completion, stimulation and production. Therefore they might not flow gas to surface at optimum rates without advanced production improvement techniques. After well stimulation and fracturing operations, invaded liquids such as filtrate will flow from the reservoir into the wellbore, as gas is produced during well cleanup. In addition, there might be production of condensate with gas. The produced liquids when loaded and re-circulated downhole in wellbores, can significantly reduce the gas production rate and well productivity in tight gas formations. This paper presents assessments of tight gas reservoir productivity issues related to liquid loading in wellbores using numerical simulation of multiphase flow in deviated and horizontal wells. A field example of production logging in a horizontal well is used to verify reliability of the numerical simulation model outputs. Well production performance modelling is also performed to quantitatively evaluate water loading in a typical tight gas well, and test the water unloading techniques that can improve the well productivity. The results indicate the effect of downhole liquid loading on well productivity in tight gas reservoirs. It also shows how well cleanup is sped up with the improved well productivity when downhole circulating liquids are lifted using the proposed methods.

Tight formations normally have production problems mainly due to very low matrix permeability and various forms of formation damage that occur during drilling completion and production operation. In naturally fractured tight gas reservoirs, gas is mainly stored in the rock matrix with very low permeability, and the natural fractures have the main contribution on total gas produc- tion. Therefore, identifying natural fractures characteristics in the tight formations is essential for well productivity evaluations. Well testing and logging are the common tools employed to evaluate well productivity. Use of image log can provide fracture static parameters, and welltest analysis can provide data related to reservoir dynamic parameters. However, due to the low matrix permeability and com- plexity of the formation in naturally fractured tight gas reservoirs, welltest data are affected by long wellbore storage effect that masks the reservoir response to pressure change, and it may fail to provide dual-porosity dual-per- meability models dynamic characteristics such as fracture permeability, fracture storativity ratio and interporosity flow coefficient. Therefore, application of welltest and image log data in naturally fractured tight gas reservoirs for meaningful results may not be well understood and the data may be difficult to interpret. This paper presents the esti- mation of fracture permeability in naturally fractured tight gas formations, by integration of welltest analysis results and image log data based on Kazemi's simplified model. Reservoir simulation of dual-porosity and dual-permeabil- ity systems and sensitivity analysis are performed for dif- ferent matrix and fracture parameters to understand the relationship between natural fractures parameters with welltest permeability. The simulation results confirmed reliability of the proposed correlation for fracture perme- ability estimation. A field example is also shown to dem- onstrate application of welltest analysis and image log data processing results in estimating average permeability of natural fractures for the tight gas reservoir.

Low permeability and complexities of rock formation in tight gas resources make it more complicated to predict well production performance and estimate gas recovery. To produce from the unconventional resources in the case that formation rock is not sensitive to damage caused by liquid invasion, hydraulic fracturing is the most common stimulation treatment to improve the production to the excepted economically rate. In term of reservoir geometry, tight sand formations are normally stacks of isolated lenses of sand bodies that are separated by shale layers. Each sand lens varies in shape and size and acts as a trap for original hydrocarbon accumulations. The sand lenses parameters such as length and width can play important role in controlling gas recovery from hydraulically fractured tight gas reservoirs. This study shows the effect of drainage pattern of the lenticular sand bodies on production performance and ultimate gas recovery in tight gas formations. Analytical and numerical simulation approaches are used in order to understand the effect of hydraulic fracture parameters and also attribution of sand lens size and shape to the drainage pattern and gas recovery in hydraulically fractured tight sand gas reservoirs. The results highlighted that in tight gas with massive hydraulic fractures, sand lens size in the direction perpendicular to hydraulic fracture wings has the major impact on gas recovery. Sand lens size in the direction parallel to hydraulic fracture wings does not have significant effect on gas recovery. When the sand lenses are isolated and small in size, from a singlewell-enhancement perspective, the gas recovery will increase significantly by performing massive hydraulic fracturing through isolated lenses.

Production logging is used to evaluate wells production performance. Interpretation of production log data provides velocity profile and contribution of each zone on total production. In multi-phase flow conditions, production log interpretation can be challenging since producing fluids do not have similar densities and travel with different speed depending on fluids properties and wellbore deviation. Production log interpretation in multi-phase producing wells requires identifying downhole flow regimes and determining velocity profile for each phase. There are different flow regimes and velocity models available, which are being used in production log interpretation to determine wells flow profile in multi phase flow. However in the case of deviated horizontal intervals, the flow model might fail to provide reliable results for gas and liquids velocities. This paper represents the use of Computational Fluid Dynamics (CFD) simulation in order to model multi-phase flow in the wellbore and evaluate velocity profile across deviated horizontal intervals. The simulation results when integrated with production log data can help estimating velocity for each phase in different flow rates and for different wellbore trajectories. The approach can help interpretation of production logging data in horizontal multi-phase producing wells, as it can predict downhole flow regimes and identify the intervals having chance of downhole liquids re-circulation. Production logging data in a gas-oil producing deviated horizontal well with water loading in wellbore was used to verify reliability of the numerical simulation. The approach could help to evaluate the well production performance with less uncertainty.

Tight gas reservoirs normally have production problems due to very low matrix permeability and significant damage during well drilling, completion, stimulation and production. Therefore, they may not flow gas at optimum rates without advanced production improvement techniques. The main damage mechanisms and the factors that have significant influence on total skin factor in tight gas reservoirs include mechanical damage to formation rock, plugging of natural fractures by mud solid particles invasion, relative permeability reduction around wellbore as a result of filtrate invasion, liquid leak-off into the formation during fracturing operations, water blocking, skin due to wellbore breakouts, and the damage associated with perforation. Drilling and fracturing fluids invasion mostly occurs through natural fractures and may also lead to serious permeability reduction in the rock matrix that surrounds the natural or hydraulic fractures. This study represents evaluation of different damage mechanisms in tight gas formations, and examines the factors that can have significant influence on total skin factor and well productivity. Reservoir simulation was carried out based on a typical West Australian tight gas reservoir in order to understand how well productivity is affected by each of the damage mechanisms such as natural fractures plugging, mud filtrate invasion, water blocking and perforation.