NO Trondheim, Norway
NO Trondheim, Norway

Time filter

Source Type

Roth S.,Numerical Rocks AS | Biswal B.,University of Stuttgart | Biswal B.,University of Delhi | Afshar G.,University of Stuttgart | And 4 more authors.
AAPG Bulletin | Year: 2011

A continuum-based pore-scale representation of a dolomite reservoir rock is presented, containing several orders of magnitude in pore sizes within a single rock model. The macroscale rock fabric from a low-resolution x-ray microtomogram was combined with microscale information gathered from high-resolution two-dimensional electron microscope images. The low-resolution x-ray microtomogram was segmented into six separate rock phases in terms of mineralogy, matrix appearances, and open- versus crystal-filled molds. These large-scale rock phases were decorated (modeled) with geometric objects, such as different dolomite crystal types and anhydrite, according to the high-resolution information gathered from the electron microscope images. This procedure resulted in an approximate three-dimensional representation of the diagenetically transformed rock sample with respect to dolomite crystal sizes, porosity, appearance, and volume of different matrix phases and pore/matrix/cement ratio. The resulting rock model contains a pore-size distribution ranging from moldic macropores (several hundred micrometers in diameter) down to mudstone micropores (<1 μm in diameter). This allows us to study the effect and contribution of different pore classes to the petrophysical properties of the rock. Higher resolution x-ray tomographs of the same rock were used as control volumes for the pore-size distribution of the model. The pore-size analysis and percolation tests performed in three dimensions at various discretization resolutions indicate pore-throat radii of 1.5 to 6 μm for the largest interconnected pore network. This also highlights the challenge to determine appropriate resolutions for x-ray imaging when the exact rock microstructure is not known. Copyright ©2011. The American Assodation of Petroleum Geologists. All rights reserved.

Fichler C.,Statoil | Odinsen T.,Statoil | Rueslatten H.,Numerical Rocks AS | Olesen O.,Geological Survey of Norway | And 2 more authors.
Tectonophysics | Year: 2011

A new crustal model for the northern North Sea was developed by gravity and magnetic modeling along the deep seismic line NSDP84-1. Utilizing vertical gradients allowed distinguishing between shallow and deep crustal sources. The upper crust is characterized by low magnetic susceptibilities and low densities, which is typical for felsic rocks. A new finding was that the deep crust below the western Viking Graben and the East Shetland Basin is the source of high magnetic anomalies combined with low gravity anomalies, which was interpreted to represent rocks with very high magnetic susceptibilities and low to intermediate densities. Such rock parameters may indicate serpentinites, but intermediate intrusives or a combination of both is also possible. Honoring the string of three near equidistant magnetic maxima, which follow the trend of the NNE-SSW striking East Shetland Basin in the map plane, it is suggested that this area is part of an island arc of the Iapetus Ocean which has been assembled during the collision between Laurentia and Baltica in late Silurian times. Partly serpentinized peridotites and intermediate intrusives will relate in such a model to slab dehydration of the subducting oceanic plate below the island arc. These inherited or synorogenic serpentinites are expected to persist in the geothermal regime of the Caledonian orogeny to a depth of at least 50. km. Increased heat flow by later rift phases will have caused metamorphism of the remaining serpentinites to meta-peridotites at depth below the present day Moho. Fluid release related to dehydration of the serpentinites may have triggered further serpentinization of the inherited, partly serpentinized rocks at shallower depth. An alternative origin for the suggested serpentinites, valid only for the area under the western part of the Viking Graben, may be synrift serpentinization due to the heavy faulting during the Jurassic rift phase. © 2011 Elsevier B.V.

Lopez O.,NumericalRocks AS | Idowu N.,NumericalRocks AS | Mock A.,NumericalRocks AS | Rueslatten H.,NumericalRocks AS | And 3 more authors.
Energy Procedia | Year: 2011

We present petrophysical data derived from pore-network modelling of CO2-brine pore systems from the Krechba CO2 Storage Site (part of the In Salah Gas Joint Venture project operated by BP, Sonatrach and Statoil). The Carboniferous sandstone reservoir formation has relatively low permeability (c. 10mD) and is characterized by abundant and variable cementation - mainly quartz, patchy carbonates, grain-coating chlorites and pyrite. These petrographic characteristics make obtaining measurements and estimation of single and multiphase flow properties challenging. Pore-scale modelling is an important new tool which can supplement special core analysis measurements by providing single and two phase flow functions for a range of rock and pore types. CO2/water relative permeability measurements have been carried out on four composite core plugs at reservoir conditions (95°C and 180 bars pore pressure). We have reviewed these experimental data and compared them to new predictions from several pore-scale reconstructions of the matching rock samples. First porosity, absolute permeability and formation factor were calculated and compared experimental data. Pore-networks were then extracted from the rock models and used as inputs to the simulation of CO 2/water displacements. Primary drainage and waterflooding sequences were simulated to establish end-point saturations (i.e. Swi and trapped CO2 saturation), capillary pressure and relative permeability curves. Very good agreement was found between the experimental results and those derived from calculations of petrophysical parameters on rock models and multiphase flow simulations through their respective pore-networks. Calculated permeability and porosity match the values estimated from the available logs, and the calculated average cementation exponent (m) for the three reconstructed samples is 2.05, comparable with the experimental value of 1.98. Swi values obtained from the simulations range from 0.29 to 0.34, similar but slightly lower than those obtained from the steady-state experimental study - 0.39 to 0.44. The simulated residual CO2 saturation ranges from 36% to 44%. The capillary trapping ensures that part of the injected CO2 will stay disconnected as isolated CO2 clusters in the pore space. These values are comparable to the residual gas saturation estimated from the experiments (from 15 to 40 %). Differences between experiments and models can be related to differences in pore types which are better defined in the pore-network models. We conclude that pore-scale modelling is able to reproduce and supplement special core analysis experiments, even when the simulations are based on relatively simple assumptions, such as non-reactive and immiscible fluids. In addition, pore-scale modelling allows the correlation of end-points with the geometry, topology and morphology of the pore space of the rock, allowing us to improve the basic understanding of CO2 trapping mechanisms in heterogeneous formations. © 2011 Published by Elsevier Ltd.

Tora G.,Norwegian University of Science and Technology | Hansen A.,Norwegian University of Science and Technology | Oren P.-E.,Numerical Rocks AS
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 2010

We present numerical results of electrical resistivity of two-phase flow in reservoir rocks using a dynamic network model. The model accounts for viscous and capillary forces, as well as wetting layers in the crevices of the pore space. It can be used as a unified model for drainage, imbibition and steady-state displacement. We use the model to study viscous effects on electrical resistivity for two-phase flow under strongly water-wet conditions. The pore network is extracted from a realistic pore space of a sandstone. For unsteady drainage and imbibition, our numerical results display capillary number dependent non-Archie behavior and hysteresis of the resistivity index. For steady-state displacement the resistivity index exhibits no significant hysteresis. For increasing capillary number we observe a higher degree of non-Archie (negative curvature) behavior. The simulated data are compared with relevant experimental data, and are in good agreement. Our conclusion is that the dynamic network model successfully reproduces viscous effects on the resistivity index in drainage, imbibition and steady-state displacement processes. Copyright 2010, Society of Petroleum Engineers.

Weltje G.J.,Technical University of Delft | Alberts L.J.H.,Numerical Rocks AS
Sedimentary Geology | Year: 2011

The question being tackled in this study is to which extent grain rearrangement contributes to porosity reduction in very well sorted quartzose sands (ideal reservoir sands). A numerical model, RAMPAGE (an acronym of random packing generator), has been developed to address this long-standing problem. RAMPAGE represents a synthesis of various algorithms designed to simulate packing of equal-sized spheres, which have been used to represent ideal solids, liquids, and gases, as well as natural porous media. The results of RAMPAGE simulations compare favourably to theoretical and experimental data from various disciplines and allow delineation of the field of gravitationally stable random packing of equal-sized spheres in the 2-D state space of porosity (P) versus mean coordination number (N). Three end-member packing states have been identified: random loose packing (RLP: P= 45.4%, N= 5.2), random close packing (RCP: P= 36.3%, N= 7.0), and bridged random close packing (Bridged RCP: P= 39.5%, N= 5.2). Unlike previously proposed models, RAMPAGE can simulate the transition from RLP to any other point in the stability field. The RLP state is fully consistent with wet-packed porosities of synthetic sands with lognormal mass-size distributions reported in the literature. The much higher in-situ porosity values reported for modern (air-packed) sands are unlikely to be preserved at depth on geological time scales. Data on the relation between intergranular volume and burial depth indicate that the observed intergranular volume reduction in the upper ~. 800. m of the sediment column corresponds to the evolution of RLP to RCP, and is thus fully explained by non-destructive grain rearrangement. © 2011 Elsevier B.V.

Tora G.,Norwegian University of Science and Technology | Oren P.-E.,Numerical Rocks AS | Hansen A.,Norwegian University of Science and Technology
Transport in Porous Media | Year: 2012

We present a dynamic model of immiscible two-phase flow in a network representation of a porous medium. The model is based on the governing equations describing two-phase flow in porous media, and can handle both drainage, imbibition, and steady-state displacement. Dynamic wetting layers in corners of the pore space are incorporated, with focus on modeling resistivity measurements on saturated rocks at different capillary numbers. The flow simulations are performed on a realistic network of a sandpack which is perfectly water-wet. Our numerical results show saturation profiles for imbibition in agreement with experiments. For free spontaneous imbibition we find that the imbibition rate follows the Washburn relation, i. e., the water saturation increases proportionally to the square root of time. We also reproduce rate effects in the resistivity index for drainage and imbibition. © 2011 Springer Science+Business Media B.V.

Ramstad T.,Numerical Rocks AS | Idowu N.,Numerical Rocks AS | Nardi C.,Numerical Rocks AS | Oren P.-E.,Numerical Rocks AS
Transport in Porous Media | Year: 2012

We present results from a systematic study of relative permeability functions derived from two-phase lattice Boltzmann (LB) simulations on X-ray microtomography pore space images of Bentheimer and Berea sandstone. The simulations mimic both unsteady- and steady-state experiments for measuring relative permeability. For steady-state flow, we reproduce drainage and imbibition relative permeability curves that are in good agreement with available experimental steady-state data. Relative permeabilities from unsteady-state displacements are derived by explicit calculations using the Johnson, Bossler and Naumann method with input from simulated production and pressure profiles. We find that the nonwetting phase relative permeability for drainage is over-predicted compared to the steady-state data. This is due to transient dynamic effects causing viscous instabilities. Thus, the calculated unsteady-state relative permeabilities for the drainage is fundamentally different from the steady-state situation where transient effects have vanished. These effects have a larger impact on the invading nonwetting fluid than the defending wetting fluid. Unsteady-state imbibition relative permeabilities are comparable to the steady-state ones. However, the appearance of a piston-like front disguises most of the displacement and data can only be determined for a restricted range of saturations. Relative permeabilities derived from unsteady-state displacements exhibit clear rate effects, and residual saturations depend strongly on the capillary number. We conclude that the LB method can provide a versatile tool to compute multiphase flow properties from pore space images and to explore the effects of imposed flow and fluid conditions on these properties. Also, dynamic effects are properly captured by the method, giving the opportunity to examine differences between steady and unsteady-state setups. © 2011 Springer Science+Business Media B.V.

Ramstad T.,Numerical Rocks AS | Rueslatten H.G.,Numerical Rocks AS | Lindeberg E.,Sintef
3rd EAGE CO2 Geological Storage Workshop: Understanding the Behaviour of CO2 in Geological Storage Reservoirs | Year: 2012

Digital pore scale images of the reservoir rocks from the Utsira formation have been modelled. The Utsira Formation on the Norwegian Continental Shelf that is already being used for CO2 sequestration. This is a saline sand aquifer of Miocene to early Pliocene age, which is covered by some 700 meters of shales and sands. The aquifer is large and CO2 is being injected into the aquifer at a depth of 1012 meters below the sea floor by a highly deviated 3 km long well from the Sleipner Field. Direct dynamic CO2/water simulations have been conducted with all relevant fluid and flow properties. From these simulations steady and un-steady state constitutive relations (relative permeability, end-point saturations) are obtained. Clear flow rate and viscosity effects are revealed from these data, which again affects the storage capabilities of the reservoir rocks.

Loading Numerical Rocks AS collaborators
Loading Numerical Rocks AS collaborators