Unconventional reservoirs such as shale gas and shale oil have become an increasingly important source of energy in the USA with potential reservoirs identified worldwide. Due to the insufficient permeability of the shale reservoirs, they require efficient stimulation using multistage hydraulic fractures to produce gas in commercial quantities. A critical challenge in the reservoirs is performance evaluation of the fracturing and characterization of the stimulated reservoir volume (SRV) for permeability and hydraulic fracture size. Conventional well test analysis in multi-stage fractured shale reservoirs may not provide reliable results due to the extensive wellbore storage effect, fracture complexities, and heterogeneity of the low-permeability reservoir. To overcome such issues, advanced well test analysis techniques integrated with rate transient analysis can be used to reduce uncertainties associated with estimation of the reservoir and hydraulic fractures' dynamic parameters. This paper proposes a practical methodology and workflow for characterizing the SRV parameters in multi-fractured wells in unconventional oil and gas reservoirs using well test and rate transient data analysis based on diffusivity equation solution for linear and elliptical flow regimes integrated with numerical reservoir simulation. A reservoir simulation model is built and run for a typical fractured shale reservoir to verify the reliability of the proposed simplified approach. Furthermore, multi-fractured unconventional reservoir field examples of well test analysis, reservoir simulation and history matching are presented to show how the stimulated reservoir volume can be characterized to perform a more reliable production forecast in shale oil and shale gas reservoirs.
Tight gas reservoirs represent a significant portion of natural gas reservoirs worldwide. Production at economical rates from tight gas reservoirs in general is very challenging not only due to the very low intrinsic permeability but also as a consequence of several different forms of formation damage that can occur during drilling, completion, stimulation, and production operations. Tight gas reservoirs generally do not produce gas at commercial rates, unless the well is completed using advanced technologies and efficiently stimulated.Well productivity in tight gas reservoirs is largely controlled by formation damage mechanisms such as liquid invasion damage into the low permeability rock matrix that reduces the near wellbore permeability as a result of temporary or permanent trapping of liquid inside the porous media. In many cases of tight gas reservoirs, the key factors that control well productivity and formation damage mechanisms are not well understood, since it is challenging to characterise them in tight formations.This paper presents evaluation of damage mechanisms and characterization of dynamic parameters in tight gas reservoirs and proposes the methods that can provide improved well productivity by minimizing damage to the tight formation. Numerical reservoir simulation is integrated with tight gas field data analysis and core flooding experiments to better understand the effect of different damage mechanisms on well productivity in order to propose the possible remedial strategies that can help achieve viable gas production rates from tight gas reservoirs.
Coal Seam Gas reservoirs are naturally fractured and the flow of fluid throughout the coal occurs by diffusion through the coal matrix and then via the cleats (network of fractures) towards the wellbore. Effective permeability of the cleats and Langmuir isotherm parameters of the matrix coal blocks are the key parameters in determining the economic viability of producing from a CSG reservoir.
Welltest analysis in CSG wells is more complicated than conventional reservoirs due to the stress sensitive permeability of the cleats and the great heterogeneity of coal. Fluid pressure inside the cleats initially controls the stress sensitive permeability. During production and at the reduced pressure near the wellbore region, the cleats have smaller aperture and less permeability than the cleats away from the wellbore due to the in-situ stresses. Conversely during injection, the cleats near the wellbore have higher permeability than the cleats away from the wellbore.
The common well test analysis methods normally provide undefined values of average permeability and skin factor, rather than addressing the effective permeability of the cleats. This study presents how to interpret the skin factor in a CSG welltest, and also proposes a methodology using integration of welltest analysis and image log data processing results for estimation of cleat characteristics in CSG reservoirs to be input in a dual porosity CSG reservoir simulation model.
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