KEY FACTORS IN SHALE GAS MODELING AND SIMULATION MODELOWANIE I SYMULACJA NIEKONWENCJONALNYCH ZŁÓŻ GAZU ZIEMNEGO Z ŁUPKÓW -KLUCZOWE PARAMETRYMulti-stage hydraulic fracturing is the method for unlocking shale gas resources and maximizing horizontal well performance. Modeling the effects of stimulation and fluid flow in a medium with extremely low permeability is significantly different from modeling conventional deposits. Due to the complexity of the subject, a significant number of parameters can affect the production performance. For a better understanding of the specifics of unconventional resources it is necessary to determine the effect of various parameters on the gas production process and identification of parameters of major importance. As a result, it may help in designing more effective way to provide gas resources from shale rocks.Within the framework of this study a sensitivity analysis of the numerical model of shale gas reservoir, built based on the latest solutions used in industrial reservoir simulators, was performed. The impact of different reservoir and hydraulic fractures parameters on a horizontal shale gas well production performance was assessed and key factors were determined.

-Natural gas from the Załęcze gas field located in the Fore-Sudetic Monocline of the Southern Permian Basin has been produced since November 1973, and continuous gas production led to a decrease in the initial reservoir pressure from 151 bar to about 22 bar until 2010. We investigated a prospective enhanced gas recovery operation at the Załęcze gas field by coupled numerical hydro-mechanical simulations to account for the CO 2 storage capacity, trapping efficiency and mechanical integrity of the reservoir, caprock and regional faults. Dynamic flow simulations carried out indicate a CO 2 storage capacity of 106.6 Mt with a trapping efficiency of about 43% (45.8 Mt CO 2 ) established after 500 years of simulation. Two independent strategies on the assessment of mechanical integrity were followed by two different modeling groups resulting in the implementation of field-to regional-scale hydro-mechanical simulation models. The simulation results based on application of different constitutive laws for the lithological units show deviations of 31% to 93% for the calculated maximum vertical displacements at the reservoir top. Nevertheless, results of both simulation strategies indicate that fault reactivation generating potential leakage pathways from the reservoir to shallower units is very unlikely due to the low fault slip tendency (close to zero) in the Zechstein caprocks. Consequently, our simulation results also emphasise that the supra-and subsaliniferous fault systems at the Załęcze gas field are independent and very likely not hydraulically connected. Based on our simulation results derived from two independent modeling strategies with similar simulation results on fault and caprock integrity, we conclude that the investigated enhanced gas recovery scheme is feasible, with a negligibly low risk of relevant fault reactivation or formation fluid leakage through the Zechstein caprocks.Résumé -Des simulations numériques de récupération assistée de gaz sur un gisement de gaz de Załęcze en Pologne confirment les capacités de stockage de CO 2 élevées et l'intégrité mécanique dudit gisement -Le gaz naturel du gisement de Załęcze, situé dans la structure monoclinale de la région des Sudètes au niveau du Bassin Permien sud, est produit depuis novembre 1973, moyennant quoi la production de gaz continue a donné lieu à une diminution de la pression initiale du réservoir de 151 bar à environ 22 bar en 2010. Nous avons effectué une étude prospective mettant en jeu une opération de récupération de gaz améliorée sur le gisement de gaz de Załęcze par des simulations

-Załęcze and Żuchlów are strongly depleted natural gas fields in aeolian sandstones of the Rotliegend, located in the central part of the Fore-Sudetic Monocline. A set of three static 3D models was generated to check the possibility of CO 2 injection for Enhanced Gas Recovery (EGR) and to check the safety of storage by means of geomechanical modeling: one regional model (ZZA) and two local models -the first for Załęcze (ZA) gas field and the second for Żuchlów (ZU) gas field. The regional model is composed of 12 stratigraphic complexes (zones) from the base of the Rotliegend to the ground surface. The local models comprise only the three lowermost complexes: fluvial deposits of the Rotliegend, aeolian sandstones of the Rotliegend (Reservoir I) and basal Zechstein limestone, Ca1. The key elements of the modeling procedure include: Quality Control (QC) of the data, interpretation of missing parameters necessary for static modeling and their integration within a geomodel. The processing workflow was elaborated to produce convergent regional and local models. The regional static model is a framework for a regional geomechanical model. The local models are the basis for dynamic simulations and local geomechanical modeling. The presented workflow could be used with some changes for geomodeling of many mature gas and oil fields.Résumé -Modèles structurels et paramétriques de la région des gisements de gaz de Załęcze et Żuchlów, Région monoclinale des Sudètes, Pologne -un exemple du déroulement d'une modélisation statique générale dans des zones de pétrole matures dans un but de CCS, EGR ou d'EOR -Załęcze et Żuchlów sont des gisements de gaz naturel largement épuisés dans les sables éoliens du Rotliegend, situés au centre de la structure monoclinale des Sudètes. Un ensemble de trois modèles en 3D statiques a été généré, afin de vérifier la possibilité d'injecter du CO 2 pour améliorer la récupération du gaz et de vérifier la sécurité de stockage au moyen d'une modélisation géomécanique : un modèle régional (ZZA) et deux modèles locaux -le premier pour le gisement de gaz de Załęcze (ZA) et le second pour le gisement de gaz de Żuchlów (ZU). Le modèle régional est

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We propose three idealized hydraulic fracture geometries (“fracture scenarios”) likely to occur in shale oil reservoirs characterized by high pore pressure and low differential in situ stresses. We integrate these geometries into a commercial reservoir simulator (CMG-IMEX) and examine their effect on reservoir fluids production. Our first, reference fracture scenario includes only vertical, planar hydraulic fractures. The second scenario has stimulated vertical natural fractures oriented perpendicularly to the vertical hydraulic fractures. The third fracture scenario has stimulated horizontal bedding planes intersecting the vertical hydraulic fractures. This last scenario may occur in mudrock plays characterized by high pore pressure and transitional strike-slip to reverse faulting stress regimes. We demonstrate that the vertical and planar fractures are an oversimplification of the hydraulic fracture geometry in anisotropic shale plays. They fail to represent the stimulated volume geometric complexity in the reservoir simulations and may confuse hydrocarbon production forecast. We also show that stimulating mechanically weak bedding planes harms hydrocarbon production, while stimulated natural fractures may enhance initial production. Our findings reveal that stimulated horizontal bedding planes might decrease the cumulative hydrocarbon production by as much as 20%, and the initial hydrocarbon production by about 50% compared with the reference scenario. We present unique reservoir simulations that enable practical assessment of the impact of varied hydraulic fracture configurations on hydrocarbon production and highlight the importance of constraining present-day in situ stress state and pore pressure conditions to obtain a realistic hydrocarbon production forecast.