Hassan Bahrami

Effect of Water Blocking Damage on Flow Efficiency and Productivity in Tight Gas Reservoirs

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.

Evaluation of Damage Mechanisms and Skin Factor in Tight Gas Reservoirs

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.

Characterizing natural fractures productivity in tight gas reservoirs

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 production. 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 complexity 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-permeability 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 estimation 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-permeability systems and sensitivity analysis are performed for different 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 permeability estimation. A field example is also shown to demonstrate application of welltest analysis and image log data processing results in estimating average permeability of natural fractures for the tight gas reservoir.

Effect of Drilling Fluid (Water-Based vs Oil-Based) on Phase Trap Damage in Tight Sand Gas Reservoirs

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 size with significant capillary pressure energy suction that imbibes and holds liquid in the capillary pores. Leak off of liquid into formation damages near wellbore permeability due to phase trap 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 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 analysed in order to show importance of damage control in hydraulic fracturing stimulation of low permeability sand formations.

Using Second Derivative of Transient Pressure in Welltest Analysis of Low Permeability Gas Reservoirs

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.

Stress Anisotropy, Long-Term Reservoir Flow Regimes and Production Performance in Tight Gas Reservoirs

Tight gas reservoirs normally have production problems due to very low matrix permeability and different damagemechanisms 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.

Reducing Mechanical Formation Damage by Minimizing Interfacial Tension and Capillary Pressure in Tight Gas

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.

Effect of Sand Lens Size and Hydraulic Fractures Parameters on Gas In Place Estimation Using

Low permeability and complexities of rock formation in tight gas reservoirs make it more complicated to predict well production performance and estimate gas recovery. To produce from the unconventional reservoirs 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 consisted by the stacks of isolated lenses of sand bodies that are separated by impermeable layers (e.g. shale). 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, gas in place (GIP) estimation using P/Z vs Gp method, and ultimate gas recovery in tight gas formations. 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 reservoirs, sand lens size in the direction perpendicular to hydraulic fracture wings has the major impact on gas recovery. Drainage of gas from the reservoirs is controlled by the sand lens width, and the size of sand lenses in the direction parallel to the hydraulic fracture wings does not have significant effect on gas recovery. The drainage area of the tight gas reservoirs is limited to the area perpendicular to the hydraulic fractures wings, and therefore P/Z vs Gp method may underestimate the value of GIP calculated for the lenticular/elliptical shape sand lenses.

Hydraulic Fractures Productivity Performance in Tight Gas Sands — A Numerical Simulation Approach

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 furture. 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 productivitiy performance. The results obtained from the welltest simulations will be plotted and used to understand the impact on reservoir response under the different hydraulic fractured scenarios. The outputs of the models can also be used to relate welltest response to the efficiency of hydraulic fractures and, therefore, productivity performance.

Liquid loading in wellbores and its effect on cleanup period and well productivity in tight gas sand reservoirs

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 pro-duction rate and well productivity in tight gas formations.