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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.

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.

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
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).

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.

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