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Summary We present a numerical method for elastic wave propagation that can incorporate fracture discontinuities in the model. The scheme is based on the Interior-Penalty Discontinuous Galerkin method and the fractures are incorporated using the linearslip model. The method is suitable for simulating the following effects of fractures in the wave field: scattering, phase-shifting, attenuation and the generation of interface waves. The method does not have restrictions on the number of fractures or their orientations, these can be oblique and have intersections. We show numerical examples using models with one fracture and two orthogonal fractures. Introduction There are many applications in Geophysics in which we are interested in determining the presence and connectivity of fractures, for example the characterization of hydrocarbon reservoirs (Liu et al., 2000; Sen et al., 2007; Zhang and Gao, 2009) and geothermal reservoirs (Wu et al., 2002, and references therein). In order to detect fractures in the subsurface we have to rely on seismic data. The presence of fractures produce the following wave phenomena: seismic anisotropy (Schoenberg and Douma, 1988), phase shifting, frequency filtering and scattering of the reflected, transmitted and converted waves (Schoenberg, 1980; Pyrak-Nolte et al., 1990; Carcione, 1996; Chen et al., 2012), fracture channel waves (Nihei et al., 1999) and fracture interface waves (Pyrak-Nolte and Cook, 1987; Pyrak-Nolte et al., 1996; Gu et al., 1996). It is therefore of practical interest to develop numerical methods for wave propagation that can incorporate fracture induced wave phenomena in the simulations. There are many methods that have been proposed in the literature to include discrete fractures into the numerical schemes. Examples of these are (1) to use locally an effective medium (Vlastos et al., 2003), (2) to incorporate locally a low velocity and low density inclusion into a finite difference scheme (Saenger and Shapiro, 2002; Saenger et al., 2004), and (3) to explicitly use a displacement discontinuity condition using the linear-slip model (Gu et al., 1996; Zhang and Gao, 2009; De Basabe et al., 2011; Carcione et al., 2012; Zhu et al., 2012; Li, 2013). In this work, we further develop on the scheme proposed in De Basabe et al. (2011) that incorporates fractures using the linear-slip model (LSM) into the interior-penalty discontinuous Galerkin method (IP-DGM) for elastic wave propagation.
Summary Numerical modeling and simulation are essential tools for developing a better understanding of the geologic characteristics of aquifers and providing technical support for future carbon dioxide (CO2) storage projects. Modeling CO2 sequestration in underground aquifers requires the implementation of models of multiphase flow and CO2 and brine phase behavior. Capillary pressure and relative permeability need to be consistent with permeability/porosity variations of the rock. It is, therefore, crucial to gain confidence in the numerical models by validating the models and results by use of laboratory and field pilot results. A published CO2/brine laboratory coreflood was selected for our simulation study. The experimental results include subcore porosity and CO2-saturation distributions by means of a computed tomography (CT) scanner along with a CO2-saturation histogram. Data used in this paper are all based on those provided by Krause et al. (2011), with the exception of the CT porosity data. We generated a heterogeneous distribution for the porosity but honoring the mean value provided by Krause et al. (2011). We also generated the permeability distribution with the mean value for the whole core given by Krause et al. (2011). All the other data, such as the core dimensions, injection rate, outlet pressure, temperature, relative permeability, and capillary pressure, are the same as those in Krause et al. (2011). High-resolution coreflood simulations of brine displacement with supercritical CO2 are presented with the compositional reservoir simulator IPARS (Wheeler and Wheeler 1990). A 3D synthetic core model was constructed with permeability and porosity distributions generated by use of the geostatistical software FFTSIM [Jennings et al. (2000)], with cell sizes of . The core was initially saturated with brine. Fluid properties were calibrated with the equation-of-state (EOS) compositional model to match the measured data provided by Krause et al. (2011). We used their measured capillary pressure and relative permeability curves. However, we scaled capillary pressure on the basis of the Leverett J-function (Leverett 1941) for permeability, porosity, and interfacial tension (IFT) in every simulation grid cell. Saturation images provide insight into the role of heterogeneity of CO2 distribution in which a slight variation in porosity gives rise to large variations in CO2-saturation distribution in the core. High-resolution numerical results indicated that accurate representation of capillary pressure at small scales was critical. Residual brine saturation and the subsequent shift in the relative permeability curves showed a significant impact on final CO2 distribution in the core.
- North America > United States > Texas (0.47)
- Europe > United Kingdom > North Sea > Central North Sea (0.24)
- Geology > Rock Type (0.46)
- Geology > Geological Subdiscipline (0.46)
Abstract CO2 flood and polymer flood are two proven and commercially practiced technologies for several decades. Traditional gas flood methods suffer from inadequate sweep efficiency and incomplete recovery of oil. Several methods to improve the volumetric sweep efficiency are practiced in field operations such as water alternating gas (WAG), polymer-gel, and foam-WAG. Polymer is traditionally added to the water flood projects to reduce the mobility of water in an effort to improve the water sweep efficiency and increase oil production especially from heterogeneous reservoirs. Both polymer and gas floods are mature technologies for improved oil recovery. However, few studies have been done on combined application of the two methods. In this paper, we conducted simulation study of the potential benefit of adding polymer to the water in the CO2 WAG process, taking the advantage of CO2 miscibility with oil and polymer conformance control during water cycle. A commercial reservoir simulator CMG-STARS is used in this study, with its PVT module CMG-WinProp. A comprehensive polymer property module is used to calculate the shear thinning rheology and non-linear mixing of polymer solution in addition to the polymer adsorption and mobility reduction factor. Field scale simulations are performed based on a real field geological model and light oil fluid properties, taking into account the heterogeneity and EOR design. The performance of each EOR method on oil recovery is also evaluated, including the water flood, CO2 flood, water alternating gas (WAG), and polymer alternating gas (PAG). Based on this pilot study, polymer alternating gas flood has the highest oil recovery factor of 74%, while WAG has 68% and water flood has 59% oil recovery factor. This field scale simulation study demonstrated positive response of PAG compared to WAG, water, or CO2 floods in oil recovery and total injection.
- North America > United States > Texas > Permian Basin > SACROC Unit > Lower Clear Fork Formation (0.99)
- North America > United States > Texas > Permian Basin > SACROC Unit > Cisco Sand Formation (0.99)
- North America > United States > Texas > Permian Basin > SACROC Unit > Canyon Reef Formation (0.99)
- (7 more...)
Abstract Ensemble-based algorithms have been successfully implemented for history matching of geological models. However, their performance is optimal only if the prior-state vector is linearly related to the predicted data and if the joint distribution of the prior-state vector is multivariate Gaussian. Moreover, the number of degrees of freedom is as large as the ensemble size, so the assimilation of large amounts of production or seismic data might lead to the ensemble collapse which results in inaccurate predictions of future performance. In this paper, we introduce a methodology that combines model classification with multidimensional scaling (MDS) and the ensemble smoother algorithm to efficiently history match fluvial and channelized reservoir models. The dynamic responses (production and seismic data) of the different ensemble members are used to compute a dissimilarity matrix. This dissimilarity matrix is then transformed into a lower-dimensional space by the use of MDS. Then, model classification is performed based on the distances between the mapped responses in the lower dimensional space and the actual observed response. In the proposed method. the transformed lower-dimensional data are used instead of original observations in the update equation to update the cluster of ensemble members that are closest to the observed response. In this manner, a limited number of ensemble members are enough to assimilate large amount of observed data without triggering the ensemble collapse problem. The updated subset of models (cluster) are used to infer a probability map and/or new hard conditioning data to re-sample new conditional members for the next iteration or next data-assimilation step. The proposed algorithm is tested by assimilating production and time-lapse seismic data into channelized reservoir models. The presented computational results show significant improvements in terms of preserving channelized features and in terms of reliability of predictions compared to the standard implementation of ensemble-based algorithms.
- Europe (1.00)
- North America > United States > Texas (0.28)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (1.00)
- Geophysics > Seismic Surveying (1.00)
- Oceania > Timor-Leste > Timor Sea > Bonaparte Basin > Oliver Field (0.93)
- Oceania > Australia > Timor Sea > Bonaparte Basin > Oliver Field (0.93)
Abstract We present a method for porous media flow in the presence of complex fracture networks. The approach uses the Mimetic Finite Difference method (MFD) and takes advantage of MFD's ability to solve over a general set of polyhedral cells. This flexibility is used to mesh fracture intersections in two and three-dimensional settings without creating small cells at the intersection point. We also demonstrate how to use general polyhedra for embedding fracture boundaries in the reservoir domain. The target application is representing fracture networks inferred from microseismic analysis.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
Novel Three-Phase Compositional Relative Permeability and Three-Phase Hysteresis Models
Beygi, Mohammad R. (University of Texas at Austin) | Delshad, Mojdeh (University of Texas at Austin) | Pudugramam, Venkateswaran S. (University of Texas at Austin) | Pope, Gary A. (University of Texas at Austin) | Wheeler, Mary F. (University of Texas at Austin)
Summary Mobility-control methods have the potential to improve coupled enhanced oil recovery (EOR) and carbon dioxide (CO2) storage technique (CO2-EOR). There is a need for improved three-phase relative permeability models with hysteresis, especially including the effects of cycle dependency so that more-accurate predictions of these methods can be made. We propose new three-phase relative permeability and three-phase hysteresis models applicable to different fluid configurations in a porous medium under different wettability conditions. The relative permeability model includes both the saturation history and compositional effects. Three-phase parameters are estimated on the basis of saturation-weighted interpolation of two-phase parameters. The hysteresis model is an extension of the Land trapping model (Land 1968) but with a dynamic Land coefficient introduced. The trapping model estimates a constantly increasing trapped saturation for intermediate-wetting and nonwetting phases. The hysteresis model overcomes some of the limitations of existing three-phase hysteresis models for nonwater-wet rocks and mitigates the complexity associated with commonly applied models in numerical simulators. The relative permeability model is validated by use of multicyclic three-phase water-alternating-gas experimental data for nonwater-wet rocks. Numerical simulations of a carbonate reservoir with and without hysteresis were used to assess the effect of the saturation direction and saturation path on gas entrapment and oil recovery.
- Europe (1.00)
- North America > United States > Texas (0.94)
- North America > United States > Alaska > North Slope Borough (0.28)
- North America > United States > Wyoming > Big Horn Basin > NPR-3 > Tensleep Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (23 more...)