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A new finite element model in studying earthquake triggering and continuous evolution of stress field.In this paper, a new finite element model (FEM) in consideration of regional stress field and an earthquake triggering factor C are proposed for studying earthquake triggering and stress field evolution in an earthquake sequence. The factor C is defined as a ratio between the shear stress and the frictional strength on a slip surface, and it can be used to tell if earthquake is triggered or not. The new FEM and the factor C are used to study the aftershock triggering of the 1976 Tangshan earthquake sequence. The results indicate that the effects of the stress field and the heterogeneity of the Tangshan earthquake fault zone on the aftershock triggering are very important. The aftershocks fallen in the earthquake triggering regions predicted by the new FEM are more than those fallen in the regions of ΔCFS≥ 0 predicted by seismic dislocation theory. new finite element model, earthquake triggering factor, regional stress field, earthquake sequence Aftershock triggering of a large earthquake is a very interesting problem. Smith et al. [1] calculated the strain energy changes induced by the larger earthquakes in southern California since 1812 and showed that the probability of the larger earthquake occurrence would be reduced at least temporarily in the region where the storied strain energy significantly decreased. Based on dislocation theory, Rybicki [2] and Yamashina [3] attributed the aftershock triggering to the increase of shear stress or shear strain. Das and Scholz [4] studied four large earthquakes and found that the areas of the shear stress increase are consistent with those of the aftershock triggering. Stein and Lisowski [5] first proposed the concept of Coulomb stress change (ΔCFS=Δτ n

We worked to establish relationships among porosity, permeability, resistivity, and elastic wave velocity of diagenetically altered sandstone. Many such relationships are documented in the literature; however, they do not consider diagenetic effects. Combining theoretical models with laboratory measured data, we derived mathematical relationships for porosity permeability, porosity velocity, porosity resistivity, permeability velocity, velocity resistivity, and resistivity permeability in diagenetically altered sandstone. The effects of clay and cementation were evaluated using introduced coefficients in these relationships. We found that clean sandstone could be modeled with Kozeny's relation; however, this relationship broke down for clay-bearing and diagenetically altered sandstone. Porosity is the first-order parameter that affects permeability, electrical, and elastic properties; clay and cement cause secondary effects on these properties. Rock physics modeling results revealed that cementation had a greater effect on elastic properties than electrical properties and clay had a larger effect on electrical properties than elastic properties. The relationships we provided can greatly help to determine permeability, resistivity, and velocity from porosity and to estimate permeability from resistivity and velocity as well as to determine resistivity from velocity measurements.

Tight gas and shale gas reservoirs provide almost half of the current U.S. domestic gas production, with significant projected increases in the next several decades. These reservoirs constitute an important play type, with opportunities for improved reservoir management in the optimization of depleted volumes as functions of well spacing and fractured well design. Reservoir simulation, together with detailed 3D geologic models, may be used for improved management, but only if the flow simulation through these models can capture the essential heterogeneity and 3D continuity of these intermittently connected rock packages. The current work will examine tight gas reservoirs, but we recognize that similar issues will arise in source rock plays.The current approach has three key technical elements: (1) We explicitly preserve the local continuity of the reservoir sands in the geologic model through the design of the simulation grid. Each simulation cell is a 1x1xN amalgamation of the geologic scale corner point cells, where "N" will vary depending upon the local sand thickness.(2) We have developed a "Well Index" based upscaling, to determine the upscaled permeability and which preserves the local reservoir quality. It does not require knowledge of the well locations within the upscaled simulation model, but it will preserve the performance of these wells. (3) The heterogeneity within each sand is preserved through the use of transmissibility upscaling, which we show performs systematically better than the usual permeability upscaling. In combination, these three elements provide simulation results which are almost indistinguishable from the fine scale model. We also examine additional approximations in which we further coarsen the model areally, and reduce the simulation time further. We develop and demonstrate our calculations on a sector model taken from the center of a full field onshore U.S. tight gas reservoir. The results are then validated using the full field model. Our approach differs from earlier studies which have attempted to preserve the global heterogeneity of the reservoir models though layer-based statistical calculations. Although these statistical approaches are superior to uniformly coarsened models, they are not as robust or as accurate as the current work constrained by local continuity. Our approach also differs in the use of accurate property upscaling techniques that simultaneously preserve the internal contrast of permeability within each sand, and the performance of wells within the model.