Stig Bakke

3-D Pore-Scale Modelling of Sandstones and Flow Simulations in the Pore Networks

A new method for generating realistic homogenous and heterogeneous 3-D pore-scale sandstone models is presented. The essence of our method is to build sandstone models which are analogs of actual sandstones by numerically modelling the results of the main sandstone-forming geological processes - sandgrain sedimentation, compaction, and diagenesis. The input data for the modelling are obtained from image analyses of thin section images of the actual sandstone. The spatial continuity of the sandstone model in the X, Y, and Z directions is determined using a scale-independent invasion percolation based algorithm. The resulting spatial continuity function, which is an ellipsoid, may be used as a heterogeneity descriptor for the sandstone model. Heterogeneity analyses show that compaction reduces the spatial continuity in the horizontal direction more rapidly than in the vertical one. The architecture and geometry of the network representation of the pore space are determined by applying various 3-D image analysis algorithms directly on the fully characterised sandstone model. A 3-D pore network which was generated from thin section data from a strongly water wet Bentheimer sandstone is used as input to a two-phase network flow simulator. Simulated transport properties for the sandstone model are in good agreement with those determined experimentally.

Process Based Reconstruction of Sandstones and Prediction of Transport Properties

We present a process based method for reconstructing the full three-dimensional microstructure of sandstones. The method utilizes petrographical information obtained from two-dimensional thin sections to stochastically model the results of the main sandstone forming processes – sedimentation, compaction, and diagenesis. We apply the method to generate Fontainebleau sandstone and compare quantitatively the reconstructed microstructure with microtomographic images of the actual sandstone. The comparison shows that the process based reconstruction reproduces adequately important intrinsic properties of the actual sandstone, such as the degree of connectivity, the specific internal surface, and the two-point correlation function. A statistical reconstruction of Fontainebleau sandstone that matches the porosity and two-point correlation function of the microtomography data differs strongly from the actual sandstone in its connectivity properties. Transport properties of the samples are determined by solving numerically the local equations governing the transport. Computed permeabilities and formation factors of process based reconstructions of Fontainebleau sandstone compare well with experimental measurements over a wide range of porosity.

Reconstruction of Berea sandstone and pore-scale modelling of wettability effects

Abstract We present an integrated procedure for estimating permeability, conductivity, capillary pressure, and relative permeability of porous media. Although the method is general, we demonstrate its power and versatility on samples of Berea sandstone. The method utilizes petrographical information obtained from 2D thin sections to reconstruct 3D porous media. The permeability and conductivity are determined by solving numerically the local equations governing the transport. The reconstructed microstructure is transformed into a topologically equivalent network that is used directly as input to a network model. Computed two-phase and three-phase relative permeabilities for water wet conditions are in good agreement with experimental data. We present a method for characterizing wettability on the pore-scale from measured Amott wettability indices. Simulated effects of wettability on waterflood relative permeabilities and oil recovery compare favourably with experimental results.

Petrophysical laboratory measurements for basin and reservoir evaluation

The quality of computer modelling in basin and reservoir studies critically depends on the quality of input data. Core measurements may directly provide such data. Cores also help establish correlations between log measured parameters and parameters required in basin or reservoir evaluation. Correlations may also permit simple index measurements to be used for data assessment instead of more tedious laboratory procedures. This paper summarizes different petrophysical laboratory techniques that can be utilized for these purposes. The importance of performing laboratory measurements under representative conditions and to account for core damage effects is underlined.

Pore-to-Field Scale Modeling of WAG

The paper describes an integrated pore-to-field scale modeling method of multiphase flow in porous media. Although the method is general, we demonstrate its power and versatility by modeling a WAG process in the Etive formation in a North Sea oil field. The method aims at capturing the relevant flow physics at different scales. Pore scale physics (μm-scale) is accounted for through predictive pore scale modeling of relative permeability and capillary pressure. The computed rock curves (cm-scale) are used to populate detailed geological models with a plausible spatial distribution of constitutive relations. Effective flow properties at the heterogeneous facies scale (m-scale) are determined by a steady state upscaling technique. Finally, the effective flow properties are implemented in a field scale (km-scale) simulation model. The simulation results show that the effective flow properties describe the reservoir WAG performance fairly accurately without any adjustment through history matching.

Extending Predictive Capabilities to Network Models

We reconstruct 3-D sandstone models which give a realistic description of the complex pore space observed in actual sandstones. The reconstructed pore space is transformed into a pore network which is used as input to a two-phase network model. The model simulates primary drainage and water injection based on a physical scenario for wettability changes at the pore level. We derive general relationships between pore structure, wettability, and capillary pressure for the different pore level displacement mechanisms which may occur in the network model. We present predicted transport properties for three different reconstructed sandstones of increasing complexity: Fontainebleau, a water wet Bentheimer, and a mixed wet reservoir rock. Predicted transport properties are in good agreement with available experimental data. For the reservoir rock, both the experiments and the simulated results show that continuos oil films allow low oil saturations to be reached during forced water injection. However, the oil relative permeability is very low.

Characterization of Unconventional Reservoir Core at Multiple Scales

PETROPHYSICS, VOL. 54, NO. 3 (JUNE 2013); PAGE 216–223; 10 FIGURES Mark Knackstedt2, Anna Carnerup2, Alexandra Golab2, Rob Sok2, Ben Young2, and Lutz Riepe3 Manuscript received by Editor May 13, 2013. 1 Originally presented at the SPWLA 53rd Annual Logging Symposium, Cartagena, Colombia, June 16-20-2012, Paper F 2 Lithicon, Suite 2 Ground oor, 73 Northbourne Avenue, Canberra ACT 2600, Australia; Email: mark.knackstedt@lithicon.com, anna.carnerup@lithicon.com, alexandra.golab@lithicon.com, rob.sok@lithicon.com, ben.young@lithicon.com 3 Petronas Carigali SDN.BHD.(PCSB), KLCC Twin Towers T2, Level 11, Kuala Lumpur, Malaysia; Email: lutz_riepe@petronas. com.my Tight unconventional reservoirs have become an increasingly common target for hydrocarbon production. Exploitation of these resources requires a comprehensive reservoir description and characterization program to estimate reserves, identify properties that control production and predict fracturability. Multiscale imaging studies from the whole core to the nanometer scale can aid in understanding the multiple contributions of heterogeneity, natural fracture density, pore types, porethroat connectivity, mineral and organic content and distribution to petrophysical response and production characteristics. In this paper we present three examples of the application of multiscale imaging to challenging unconventional reservoirs: a deep, clastic tight-gas reservoir; a fractured basement reservoir; and coal-seam gas reservoir. All these samples exhibit features at multiple scales, which present major challenges to petrophysical evaluation and understanding of reservoir engineering properties. In all cases, characterization of heterogeneity and geological rock typing is undertaken at the core scale. Mineralogy and porosity/microporosity characterization is then mapped at the pore scale with varying modes of microcomputed tomography ( CT) 3D imaging. Focusedion-beam scanning electron microscopy (FIBSEM) imaging can then be used to reveal the nanoporous structure of the key phases controlling hydrocarbon movement within the core material. Petrophysical properties (porosity, permeability, elastic moduli) can also be computed for each key phase and the data upscaled using standard techniques. The presented case histories demonstrate that multiscale imaging and modeling provides a complimentary method to existing core-measurement techniques via characterization of the distribution and nature of different pore types and matrix components. This can enable improved classi cation and aids the prediction of elastic and dynamic rock properties even on rock fragments that are not suitable for conventional core analysis. In addition, the results have the potential to enhance our understanding of petrophysical, fracturing and multiphase ow processes in challenging unconventional reservoirs with low porosities and permeabilities.