Center for Integrated Petroleum Research

Bergen, Norway

Center for Integrated Petroleum Research

Bergen, Norway

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Skurtveit E.,Center for Integrated Petroleum Research | Skurtveit E.,University of Bergen | Skurtveit E.,Norwegian Geotechnical Institute | Torabi A.,Center for Integrated Petroleum Research | And 2 more authors.
Journal of Geophysical Research: Solid Earth | Year: 2013

Shear-enhanced compaction in shallow sandstone reservoirs has been investigated in laboratory experiments using high-pressure triaxial testing of poorly lithified sandstone and sand. We have studied the deformation mechanism involved during shear-enhanced compaction and controlling parameters for yield stress at varying confining pressures for sandstone/sand with different grain sizes, porosities, and packing. Experimental testing provides insights into the deformation mechanism during hydrostatic and axial compression of coarse- and fine-grained sands with different packing including (1) natural coarse-grained sandstone, (2) densely packed fine-grained sand, and (3) loosely packed fine-grained sand. Monitoring of deformation and ultrasonic velocity during deformation indicates porosity loss, compaction, and strain hardening for most of the samples. Visualization of deformation using pretest and posttest X-ray imaging and thin sections demonstrates localized deformation fabrics and grain damage. The results show grain rearrangement as the controlling deformation mechanism for material at low stress and high porosity, whereas for lower porosity and higher stress, grain fracturing controlled the deformation. The most pronounced localization of deformation was observed for the coarse-grained, low-porosity material. A Cam-Clay cap model was used to describe the porosity loss during compaction and shear-enhanced compaction, demonstrating large inelastic compaction with increasing confining pressure. Yield stress and end caps for poorly lithified sandstone are observed for various porosities and stress conditions and found to be lower than predicted using empirical relationships for sandstone. © 2013. American Geophysical Union. All Rights Reserved.


Zhang Y.,Chevron | Oliver D.S.,Center for Integrated Petroleum Research
SPE Journal | Year: 2011

The increased use of optimization in reservoir management has placed greater demands on the application of history matching to produce models that not only reproduce the historical production behavior but also preserve geological realism and quantify forecast uncertainty. Geological complexity and limited access to the subsurface typically result in a large uncertainty in reservoir properties and forecasts. However, there is a systematic tendency to underestimate such uncertainty, especially when rock properties are modeled using Gaussian random fields. In this paper, we address one important source of uncertainty: the uncertainty in regional trends by introducing stochastic trend coefficients. The multiscale parameters including trend coefficients and heterogeneities can be estimated using the ensemble Kalman filter (EnKF) for history matching. Multiscale heterogeneities are often important, especially in deepwater reservoirs, but are generally poorly represented in history matching. In this paper, we describe a method for representing and updating multiple scales of heterogeneity in the EnKF. We tested our method for updating these variables using production data from a deepwater field whose reservoir model has more than 200,000 unknown parameters. The match of reservoir simulator forecasts to real field data using a standard application of EnKF had not been entirely satisfactory because it was difficult to match the water cut of a main producer in the reservoir. None of the realizations of the reservoir exhibited water breakthrough using the standard parameterization method. By adding uncertainty in largescale trends of reservoir properties, the ability to match the water cut and other production data was improved substantially. The results indicate that an improvement in the generation of the initial ensemble and in the variables describing the property fields gives an improved history match with plausible geology. The multiscale parameterization of property fields reduces the tendency to underestimate uncertainty while still providing reservoir models that match data. Copyright © 2011 Society of Petroleum Engineers.


Fossen H.,Center for Integrated Petroleum Research | Fossen H.,University of Bergen | Schultz R.A.,University of Nevada, Reno | Torabi A.,Center for Integrated Petroleum Research
Journal of Structural Geology | Year: 2011

Observations from quartz-rich eolian Navajo Sandstone in the Buckskin Gulch site in southernmost Utah show that pure compaction bands only occur in sandstones where current porosity > 0.29 ± 3, permeability > 10 ± 7 darcy, and grain size > 0.4. mm - properties restricted to the lower and most coarse-grained and well-sorted parts of grain flow units within the dune units. Hence a direct correlation between stratigraphy and band occurrence has been established that can be used to predict deformation band occurrences in similar sandstone reservoirs.We show that the pure compaction bands formed perpendicular to a subhorizontal σ1, bisecting conjugate sets of shear-enhanced compaction bands. The latter bands locally developed into shear-dominated bands that transect entire dune units, suggesting that an increase in the amount of simple shear promotes band propagation into less porous and permeable lithologies.Stress considerations indicate that, as a continuous and overlapping sequence of events, pure compaction bands in quartz-rich Navajo Sandstone initiated at 10-20. MPa (∼1. km depth), followed by shear-enhanced compaction bands that locally developed into more stratigraphically extensive shear-dominated bands. The rare combination of special lithologic and stress conditions may explain why pure compaction bands are rarely observed in naturally deformed sandstones. © 2011 Elsevier Ltd.


Totland C.,University of Bergen | Lewis R.T.,Center for Integrated Petroleum Research | Nerdal W.,University of Bergen
Journal of Colloid and Interface Science | Year: 2011

In this study, 1H NMR is used to investigate properties of sodium dodecyl sulfate (SDS), tetradecyl trimethyl ammonium bromide (TTAB), and dodecyl trimethyl ammonium bromide (DTAB) adsorbed on kaolin by NMR T 1 and T 2 measurements of the water proton resonance. The results show that adsorbed surfactants form a barrier between sample water and the paramagnetic species present on the clay surface, thus significantly increasing the proton T 1 values of water. This effect is attributed to the amount of adsorbed surfactants and the arrangement of the surfactant aggregates. The total surface area covered by the cationic (DTAB and TTAB) and anionic (SDS) surfactants could be estimated from the water T 1 data and found to correspond to the fractions of negatively and positively charged surface area, respectively. For selected samples, the amount of paramagnetic species on the clay surface was reduced by treatment with hydrofluoric (HF) acid. For these samples, T 1 and T 2 measurements were taken in the temperature range 278-338K, revealing detailed information on molecular mobility and nuclear exchange for the sample water that is related to surfactant behavior both on the surface and in the aqueous phase. © 2011 Elsevier Inc.


Aas T.E.,Center for Integrated Petroleum Research | Howell J.A.,Center for Integrated Petroleum Research | Janocko M.,University of Bergen | Jackson C.A.-L.,Imperial College London
Marine and Petroleum Geology | Year: 2010

It is widely recognised that palaeobathymetry is a key control on the distribution of turbidite deposits. Thus, the utilisation of palaeobathymetric surfaces as an input for numerical turbidity current modelling offers a potentially powerful method to predict the distribution of deep marine sands in ancient (subsurface or outcrop) successions. Such an approach has been tested on an Aptian turbidite deposit from the Buchan Graben, UK Central North Sea, where modelled sand distributions could be quality controlled against available well data. Palaeobathymetric (base Aptian sand) surfaces are re-created from a surface-based 3D model by stepwise backstripping of post-Aptian overburden and removal of the post-depositional structural overprint. Key input parameters such as: (i) initial porosity and compaction factor assigned to the overburden and underburden; (ii) the restoration of structural overprint; and (iii) the crustal response to removal of overburden (Airy vs. Flexural Isostasy), are associated with significant uncertainty. Thus, to assess this uncertainty, various palaeobathymetric surfaces are re-created by systematically modelling extreme values of individual input parameters. The effects of single input parameter variability on output surface morphology are quantified by spatial comparison of appropriate surfaces. Out of the 20 palaeobathymetric surfaces that were re-created, three were selected as input for process-based, numerical turbidity current simulations. The simulation software (Flow 3D™) uses computational-fluid-dynamics (CFD) to model depositional patterns, while the effects of flow turbulence are simulated using the renormalization-group (RNG) model. The location of flow introduction into the model (sediment input point) as well as flow input parameters (volume of sediment, duration of flow, velocity, height and width) are fixed for all three surfaces to ensure that differences in flow behaviour and sand distribution can be attributed to spatial variations between input surfaces alone. Simulated sand distributions were compared against sand thicknesses from well data to indicate the reliability of the three palaeobathymetric surface geometries. © 2009 Elsevier Ltd. All rights reserved.


Feng T.,Center for Integrated Petroleum Research | Mannseth T.,Center for Integrated Petroleum Research | Mannseth T.,University of Bergen
Computational Geosciences | Year: 2010

We consider the impact of using time-lapse seismic data in addition to production data for permeability estimation in a porous medium with multiphase fluid flows, such as a petroleum reservoir under water-assisted production. Since modeling seismic wave propagation in addition to modeling fluid flows in the reservoir is quite involved, it is assumed that the time-lapse seismic data have already been inverted into fluid saturation differences (pseudoseismic data). Because an inversion process often leads to considerable error growth, we will consider pseudoseismic data with large uncertainties. The impact of pseudoseismic data is assessed through permeability estimation with and without such data and through application of some uncertainty measures for the estimated parameters. A multiscale algorithm is used for the parameter estimations, so that potential differences in attainable permeability resolution will be easily revealed. The numerical examples clearly indicate that the permeability estimation problem is stabilized at a higher level of resolution when pseudoseismic data are applied in addition to production data, even if the pseudoseismic data have large associated uncertainties. Use of the parameter uncertainty measures confirm these results. © 2010 Springer Science+Business Media B.V.


Harada M.,Yamagata University | Kiermaier M.,University of Bayreuth | Wassermann A.,University of Bayreuth | Yorgova R.,Center for Integrated Petroleum Research
IEEE Transactions on Information Theory | Year: 2010

In this paper, we construct new binary singly even self-dual codes with larger minimum weights than the previously known singly even self-dual codes for several lengths. Several known construction methods are used to construct the new self-dual codes. © 2006 IEEE.


Pettersen O.,Center for Integrated Petroleum Research
Open Petroleum Engineering Journal | Year: 2010

Compaction-induced permeability reduction in a producing reservoir rock/soil can be significant, but nevertheless is often neglected or overly simplified in reservoir simulations. Provided examples show that the commonly used compaction models in reservoir simulators are not capable of capturing the actual spatial variation of the compaction, which generally is more complex than the simplified models predict. The only way to compute a reliable compaction state is by rock mechanics simulation. The computing time can be considerably reduced by an accurate and efficient procedure, which has been used to do the compaction modeling and study the effects of permeability reduction on fluid flow and production. Weak, moderate, and strong materials behave differently when loaded, such that large contrasts in initial permeability can be reduced by increasing load (depletion), resulting in more homogeneous flow. It is demonstrated how this can be utilized to achieve better sweep efficiency, reduced water production and increased oil recovery. The effects are especially pronounced when the pressure reduction is considerable ("pressure blowdown"). The data used are from Brent-type reservoirs, but the results also apply to a wider range of reservoirs. © Øystein Pettersen; Licensee Bentham Open.


Bolandtaba S.F.,Center for Integrated Petroleum Research | Skauge A.,Center for Integrated Petroleum Research
Transport in Porous Media | Year: 2011

A novel concept for modeling pore-scale phenomena included in several enhanced oil recovery (EOR) methods is presented. The approach combines a quasi-static invasion percolation model with a single-phase dynamic transport model in order to integrate mechanistic chemical oil mobilization methods. A framework is proposed that incorporates mobilization of capillary trapped oil. We show how double displacement of reservoir fluids can contribute to mobilize oil that are capillary trapped after waterflooding. In particular, we elaborate how the physics of colloidal dispersion gels (CDG) or linked polymer solutions (LPS) is implemented. The linked polymer solutions consist of low concentration partially hydrolyzed polyacrylamide polymer crosslinked with aluminum citrate. Laboratory core floods have shown demonstrated increased oil recovery by injection of linked polymer solution systems. LPS consist of roughly spherical particles with sizes in the nanometer range (50-150 nm). The LPS process involve mechanisms such as change in rheological properties effect, adsorption and entrapment processes that can lead to a microscopic diversion and mobilization of waterflood trapped oil. The purpose is to model the physical processes occurring on pore scale during injection of linked polymer solutions. A sensitivity study has also been performed on trapped oil saturation with respect to wettability status to analyze the efficiency of LPS on different wettability conditions. The network modeling results suggest that weakly wet reservoirs are more suitable candidates for performing linked polymer solution injection. © 2011 The Author(s).


Pettersen O.,Center for Integrated Petroleum Research
Computational Geosciences | Year: 2012

The layering in reservoir simulation grids is often based on the geology, e. g., structure tops. In this paper we investigate the alternative of using horizontal layers, where the link to the geology model is by the representation of the petrophysics alone. The obvious drawback is the failure to honor the structure in the grid geometry. On the other hand, a horizontal grid will honor the initial fluid contacts perfectly, and horizontal wells can also be accurately represented. Both these issues are vital in thin oil-zone problems, where horizontal grids may hence be a viable alternative. To investigate this question, a number of equivalent simulation models were built for a segment of the Troll Field, both geology-based and horizontal, and various combinations of these. In the paper, it is demonstrated that the horizontal grid was able to capture the essentials of fluid flow with the same degree of accuracy as the geology-based grid, and near-well flow was considerably more accurate. For grids of comparable resolution, more reliable results were obtained by a horizontal grid than a geo-grid. A geo-grid with local grid refinement and a horizontal grid produced almost identical results, but the ratio of computing times was almost 20 in favor of the horizontal grid. In the one-phase regions of the reservoir, relatively coarse cells can be used without significant loss of accuracy. © 2011 The Author(s).

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