Heinemann Z.E.,University of Leoben |
Mittermeir G.M.,Heinemann Oil GmbH
Transport in Porous Media | Year: 2012
Kazemi et al. (SPE Reserv Eng 7(2):219-227, 1992) suggested an empirical matrix-fracture transfer function, verified based on experimental data of Mattax and Kyte (Trans AIME 225(15):177-184, 1962), to model fluid flow in naturally fractured dual porosity petroleum reservoirs using a dual-porosity numerical simulator. Their generalized shape factor should be valid for all possible irregular matrix blocks. The factor is calculated based on the volume of the matrix block, the surface open to flow in all directions and the distances of these surfaces to the centre of the matrix block. The summation is done over all open surfaces of a matrix block. Kazemi et al. (1992) showed that for rectangles and cylinders the formula reduces to the well-known forms of the shape factor. By the time, many authors indicated the validity of the formula, but no theoretical proof was offered for that so far. This study derives the Kazemi et al. (1992) shape factor using control volume finite difference discretization on the fracture-matrix dual continuum. The matrix blocks are handled as Voronoi polyhedra. The derivation is given for both isotropic and tensorial matrix permeability. Based on this derivation the authors conclude that the Kazemi et al. (SPE Reserv Eng 7(2):219-227, 1992) formula is exact under pseudo-steady-state conditions within the dual continuum mathematical concept of natural fractured dual porosity systems. © 2011 Springer Science+Business Media B.V.
Hollt T.,King Abdullah University of Science and Technology |
Freiler W.,SimVis GmbH |
Gschwantner F.-M.,is Research Center |
Doleisch H.,SimVis GmbH |
And 2 more authors.
IEEE Transactions on Visualization and Computer Graphics | Year: 2012
The most important resources to fulfill today’s energy demands are fossil fuels, such as oil and natural gas. When exploiting hydrocarbon reservoirs, a detailed and credible model of the subsurface structures is crucial in order to minimize economic and ecological risks. Creating such a model is an inverse problem: reconstructing structures from measured reflection seismics. The major challenge here is twofold: First, the structures in highly ambiguous seismic data are interpreted in the time domain. Second, a velocity model has to be built from this interpretation to match the model to depth measurements from wells. If it is not possible to obtain a match at all positions, the interpretation has to be updated, going back to the first step. This results in a lengthy back and forth between the different steps, or in an unphysical velocity model in many cases. This paper presents a novel, integrated approach to interactively creating subsurface models from reflection seismics. It integrates the interpretation of the seismic data using an interactive horizon extraction technique based on piecewise global optimization with velocity modeling. Computing and visualizing the effects of changes to the interpretation and velocity model on the depth-converted model on the fly enables an integrated feedback loop that enables a completely new connection of the seismic data in time domain and well data in depth domain. Using a novel joint time/depth visualization, depicting side-by-side views of the original and the resulting depth-converted data, domain experts can directly fit their interpretation in time domain to spatial ground truth data. We have conducted a domain expert evaluation, which illustrates that the presented workflow enables the creation of exact subsurface models much more rapidly than previous approaches. © 2012 IEEE.
Hollt T.,King Abdullah University of Science and Technology |
Beyer J.,King Abdullah University of Science and Technology |
Gschwantner F.,is Research Center |
Muigg P.,SimVis GmbH |
And 3 more authors.
IEEE Pacific Visualization Symposium 2011, PacificVis 2011 - Proceedings | Year: 2011
Increasing demands in world-wide energy consumption and oil depletion of large reservoirs have resulted in the need for exploring smaller and more complex oil reservoirs. Planning of the reservoir valorization usually starts with creating a model of the subsurface structures, including seismic faults and horizons. However, seismic interpretation and horizon tracing is a difficult and error-prone task, often resulting in hours of work needing to be manually repeated. In this paper, we propose a novel, interactive workflow for horizon interpretation based on well positions, which include additional geological and geophysical data captured by actual drillings. Instead of interpreting the volume slice-by-slice in 2D, we propose 3D seismic interpretation based on well positions. We introduce a combination of 2D and 3D minimal cost path and minimal cost surface tracing for extracting horizons with very little user input. By processing the volume based on well positions rather than slice-based, we are able to create a piecewise optimal horizon surface at interactive rates. We have integrated our system into a visual analysis platform which supports multiple linked views for fast verification, exploration and analysis of the extracted horizons. The system is currently being evaluated by our collaborating domain experts. © 2011 IEEE.
Heinemann Z.E.,Heinemann Oil GmbH |
Mittermeir G.M.,Heinemann Oil GmbH |
Gherryo Y.S.,Gulf |
Oil Gas European Magazine | Year: 2010
The article presents a new approach to History Matching of hydrocarbon reservoirs, and its successful application. In a conventional approach the static geological model is built first, containing also the wells and a certain kind of representation of the outer aquifer. The model must be verified, i. e. history matched by upscaling to a dynamic model and by comparing its result to the production history. If the comparison is successful, the model is suitable for forecasting and for evaluating future development scenarios. The simulator calculates the bottom hole pressures, gas oil ratio (GOR) and water cut (WC) over the entire production history. The reservoir model is modified, if these values do not match the measured ones. The new method does the opposite: the production and pressure data are fixed and the Simulator decides under which conditions the fixed parameters could be met. The pressures, the GORs and WCs are data and not results. The calculation shows where and under which conditions the well could operate in the same manner as it really did and from where how much water must flow in. The name of this approach is Target Pressure and Phase Method, abbreviated TPPM. The article is presented in two consecutive issues of this journal. This issue completes the work with a full field application of TPPM, while the last (September) issue concentrated on the idea, the TPPM workflow and a small example.
Egger S.,University of Leoben |
Egger S.,Heinemann Oil GmbH |
Davis J.C.,Heinemann Oil GmbH |
Heinemann Z.,Heinemann Oil GmbH
IAMG 2010 Budapest - 14th Annual Conference of the International Association for Mathematical Geosciences | Year: 2010
The "Target Pressure and Phase Method" (TPPM) is being implemented so mismatches between dynamic and static models of oil field reservoirs can be avoided. An initial conditional stochastic model is adjusted by connecting wells that do not correctly match their history during initial simulation to more distant cells that will provide appropriate well performance histories. These cells are then exchanged with cells in the well drainage areas to achieve a history match. In a final step, the model is regenerated by simulated annealing conditional on the new drainage area cells.