ORCID Profile
0000-0002-3792-1896
Current Organisations
Delft University of Technology
,
Heriot-Watt University
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Publisher: Elsevier BV
Date: 2023
DOI: 10.1016/J.JCIS.2022.09.082
Abstract: Underground hydrogen (H We have performed in situ X-ray imaging during a flow experiment to investigate pore-scale processes during H The sandstone was found to be wetting to the brine and non-wetting to H
Publisher: American Association of Petroleum Geologists AAPG/Datapages
Date: 04-2013
DOI: 10.1306/12171212229
Publisher: Elsevier BV
Date: 15-05-2006
Publisher: SPE
Date: 11-06-2007
DOI: 10.2118/107485-MS
Abstract: Discrete-fracture modeling and simulation of two-phase flow in realistic representations of fractured reservoirs can now be used for the design of IOR and EOR strategies. Thus far, however, discrete fracture simulators fail to include a third compressible gaseous phase. This hinders the investigation of the performance of gas-gravity drainage, water alternating gas injection, and blow-down in fractured reservoirs. Here we present a new numerical method that expands the capabilities of existing Black-Oil models for three-component – three-phase flow in three ways: (i) It utilizes a finite element - finite volume discretization generalized to unstructured hybrid element meshes. (ii) It employs higher-order accurate representations of the flux terms. (iii) Flash calculations are carried out with an improved equation of state allowing for a more realistic treatment of phase behavior. We illustrate the robustness of this numerical method in several applications. First, quasi-1D simulations are used to demonstrate grid convergence. Then, 2D discrete fracture models are employed to illustrate the impact of mesh quality on predicted production rates in discrete fracture models. Finally, the proposed method is used to simulate three-component – three-phase flow in a realistic 2D model of fractured limestone mapped in the Bristol Channel, U.K. and a 3D stochastically generated discrete fracture model.
Publisher: Elsevier BV
Date: 06-2011
Publisher: Springer Science and Business Media LLC
Date: 06-2006
Publisher: Springer Science and Business Media LLC
Date: 06-2006
Publisher: American Association of Petroleum Geologists AAPG/Datapages
Date: 10-2006
DOI: 10.1306/05090605153
Publisher: Society of Petroleum Engineers (SPE)
Date: 31-05-2009
DOI: 10.2118/107485-PA
Abstract: Discrete-fracture modeling and simulation of two-phase flow in realistic representations of fractured reservoirs can now be used for the design of improved-oil-recovery (IOR) and enhanced-oil-recovery (EOR) strategies. Thus far, however, discrete-fracture simulators usually do not include a third compressible gaseous phase. This hinders the investigation of the performance of gas gravity drainage, water alternating gas injection, and blowdown in fractured reservoirs. We present a new numerical method that expands the capabilities of existing black-oil models for three-component, three-phase flow in three ways: (a) It uses a finite-element/finite-volume discretization generalized to unstructured hybrid element meshes. (b) It employs higher-order accurate representations of the flux terms. (c) Flash calculations are carried out with an improved equation of state allowing for a more realistic treatment of phase behavior. We illustrate the robustness of this numerical method in several applications. First, quasi-ID simulations are used to demonstrate grid convergence. Then, 2D discrete-fracture models are used to illustrate the effect of mesh quality on predicted production rates in discrete-fracture models. Finally, the proposed method is used to simulate three-component, three-phase flow in a realistic 2D model of fractured limestone mapped in the Bristol Channel, UK, and create a 3D stochastically generated discrete-fracture model.
Publisher: SPE
Date: 19-09-2010
DOI: 10.2118/135135-MS
Abstract: Hydrocarbon reservoirs commonly contain an array of fine-scale structures that are below the resolution of seismic images. These features may impact flow behavior and recovery, but their specific impacts may be obscured by the upscaling process for sector and field-scale reservoir simulations. It is therefore important to identify those situations in which subseismic structures can introduce significant departures from full-field flow predictions. Using exposures of Jurassic carbonate outcrops near the village of Amellago in the High Atlas Mountains of Morocco, we have developed a series of flow simulations to explore the interactions of a hierarchical fracture network with the rock matrix of carbonate r strata. Model geometries were constructed in CAD software using field interpretations and LiDAR1 data of an outcrop area that is 350 m long by 100 m high. The impact of water injection on oil recovery between an injector and producer pair was investigated. Simulations were performed by a single medium reservoir simulator using a single mesh to represent fracture planes as well as rock-matrix volumes. The effects of changing scenarios for rock permeability and porosity as well as facture permeability distributions were investigated. First-order results show that the best recovery was achieved by a model with a high permeability, homogeneous matrix combined with a heterogeneous fracture network. The worst recovery scenario was given by a model with low, homogeneous permeability and high fracture permeabilities. After approximately 450 days there is a ergence in recovery profiles. Three models continue to recover oil while average oil saturations for the other 4 models start to plateau. The ergence does not simply reflect homogeneous vs. heterogeneous matrix models but captures a threshold between high and medium fracture-permeability scenarios that determines whether recovery continues in late time or the well starts to water out. The results highlight the importance of the permeability contrasts between the matrix and the fractures for overall recovery and the very significant impact that fractures can have on recovery by creating shadow zones and providing critical connections between permeable layers. The presence of the hierarchical fracture network developed strong fingering even in homogeneous matrix cases and evolving velocity patterns reveal competing fluid pathways among matrix and fracture routes. Insights from these models can help to develop production strategies to improve recovery from fractured carbonate reservoirs and provide an initial platform from which to extend further evaluations of different populations of conductive and baffling structures, spatial variations in wettability and capillary pressures and well positions.
Publisher: Wiley
Date: 11-2004
Publisher: Geological Society of London
Date: 2007
DOI: 10.1144/SP292.22
Publisher: American Geophysical Union (AGU)
Date: 2005
DOI: 10.1029/2004JB003362
Publisher: Wiley
Date: 08-2002
Publisher: Elsevier BV
Date: 12-2008
Publisher: SPE
Date: 02-02-2009
DOI: 10.2118/118924-MS
Abstract: We have been able to solve a reservoir simulation problem which was previously thought of as intractable: We simulated multiphase displacement, including viscous, capillary, and gravitational forces, for highly resolved and geologically realistic models of naturally fractured reservoirs (NFR) at the sector, i.e. kilometre, scale with very reasonable runtime. This has been possible because we used massive parallelisation and hierarchical solvers in conjunction with a new discrete fracture and matrix modelling (DFM) technique that is based on mixed-dimensional unstructured hybrid-element discretisations. High-resolution DFM simulations are important to resolve the non-linear coupling of small scale capillary – viscous and large scale gravitational – viscous processes adequately for sector scale NFR. Cross-scale process coupling in NFR controls oil recovery and NFR often exhibit power-law fracture length distributions, i.e. they do not possess an REV, and highly permeable fractures can extend over the full hydrocarbon column height. As a consequence, emergent displacement patterns have been observed which are difficult to quantify using traditional means of upscaling. However, such patterns could now be used as benchmarks to reach a better consensus on the correctness of promising new upscaling techniques. The parallel DFM technologies presented here allow us to to obtain these results much more efficiently and hence explore the parameter space in greater detail. We observed a linear scaling behaviour for up to 64 processes and a significant decrease in runtime when applying our parallel DFM approach to three highly refined NFR simulations. These contain thousands of fractures, up to 5 million elements, and have local grid-refinements below 1 m for model dimensions between 1 and 10 kilometres. We achieved this excellent speedup because we reduced inter-processor communication by minimising the overlap between in idual domains and decreased idle time of in idual processors by distributing the number of unknowns equally among the processors.
Publisher: Geological Society of London
Date: 05-09-2012
DOI: 10.1144/SP374.8
Location: United Kingdom of Great Britain and Northern Ireland
No related grants have been discovered for Sebastian Geiger.