Roe P.,Norwegian Computing Center |
Kjonsberg H.,Norwegian Computing Center |
74th European Association of Geoscientists and Engineers Conference and Exhibition 2012 Incorporating SPE EUROPEC 2012: Responsibly Securing Natural Resources | Year: 2012
Traditionally fault seal calculations take place directly within the simulation grid. This approach works well for grids where all the faults are aligned along the grid pillars, but implementing an algorithm that works with stair-stepped representation of the faults has proven to be very difficult. Especially the calculation of the displacement field used both indirectly in the fault seal parameter calculation and directly in the calculation of fault zone permeability is challenging. It is hard to find where the different grid layers intersect the fault trace, and the layers are not always completely represented on both sides of the fault. We present a novel algorithm where the calculation of the fault zone permeability is carried out on a 2D plane representing the fault surface. The input parameters needed for calculating the fault zone permeability are resampled from the simulation grid onto the 2D plane, while the resulting fault zone permeability is resampled back into the simulation grid, prior to calculation of the fault transmissibility. The new approach is shown to generate good results both for pillar-faulted grids, and for grids with stairstepped faults, and also works well near complex truncations.
Demyanov V.,Heriot - Watt University |
Gopa K.,Roxar |
Arnold D.,Heriot - Watt University |
Elfeel M.A.,Heriot - Watt University
14th European Conference on the Mathematics of Oil Recovery 2014, ECMOR 2014 | Year: 2014
Uncertainty in the distribution of fractures has a high impact on the fluid flow in oil reservoirs. The challenge is to propagate the uncertainty in the fracture distribution patterns into the reservoir flow response. Optimisation reservoir production under this geological uncertainty would result in to more robust operational decisions to maximise recovery and minimise production costs. Commonly the uncertainty in fracture distribution is described by multiple discrete fracture network realisations (DFN) that represent a range of geologically plausible scenarios. The range of fracture distribution scenarios is captured by spatially varying properties such as facture density distribution, orientation, length etc. Fracture characteristics depend on both geomechanical factors and rock properties, which, therefore, have a high impact on the flow response. The corresponding flow response is also subject to upscaling errors introduced by the choice of the upscaling approach. Therefore, production optimisation (well placements, perforation etc.) becomes a computationally challenging task to perform over a range of possible realisations, modelling choices and upscaling methods required to account for the associated uncertainties. We propose an approach that performs well placement optimisation over a selected sub-set of the reservoir realisations, which would represent the range of uncertainties introduced by geological and upscaling factors. The sub-set of the DFN scenarios is obtained through clustering the exhaustive set of flow response realisations in a flow metric space using a multi-dimensional scaling. The obtained clusters define a limited set of flow scenarios that can be represented by a much smaller number of selected realisations, which still adequately characterise the spread of uncertainty associated with the exhaustive set. Optimisation over a limited set of selected realisations corresponding to the range of the flow response scenarios provides a set of well configurations that maximise oil recovery and minimise the costs (produced water and the number of wells). Optimisation over multiple geological scenarios with respect to the geological uncertainty identifies the most robust development decisions than the one based on the optimisation over a single scenario. Use of multi-objective optimisations provides a greater potential variability of possible solutions, which increases the confidence in the uncertainty prediction.
Abrahamsen P.,Norwegian Computing Center |
Dahle P.,Norwegian Computing Center |
Integrated Reservoir Modelling: Are We Doing it Right? | Year: 2012
The use of horizontal well data in 3D reservoir modeling has become an increasingly important task as the use of horizontal wells has become common practice. Standard gridding approaches are based on the use of well picks to define the positions of stratigraphic surfaces along well bores. Horizontal wells however, are often drilled almost parallel to the stratigraphic layering so the number of horizons intersected along a horizontal well can be relatively few. Therefore, horizontal sections of the well can be used to constrain the structural position of reservoir zones. A robust, geostatistical approach has been developed to ensure consistent use of horizontal well data in the construction of 3D structural models. Kriging is used for prediction of surface location based on well picks and constraints obtained from zone logs along horizontal wells. In contrast to standard approaches, all well data (picks and constraints) from all surfaces are treated simultaneously and will have impact on all surfaces above and below. The geostatistical approach is fast and reproducible, and allows structural models to be updated continuously as new wells are drilled. The uncertainty can be evaluated by kriging error maps or by generating stochastic realizations that honor all the well data.
Escalona A.,University of Stavanger |
First Break | Year: 2013
We performed forward basin modelling along a profile in the Leeward Antilles, southern Caribbean region, to evaluate the thermal effect that the south-dipping Caribbean slab may have on the evolution of the petroleum systems in the Cenozoic basins. The basins were formed along a former volcanic island arc and back arc region, and have been filled by terrigenous and carbonate sediments since the late Eocene. Since the middle Miocene, the region has been affected by southeastward diachronous subduction of the Caribbean plate beneath South America. We modelled the effect of the subducting slab by treating it as a cold igneous intrusion that insulates the overlying sediments from the asthenosphere. Basin modelling shows that the slab effect results in a reduced transformation ratio in the lower Palaeogene source rocks and lower temperatures in the lower Miocene reservoirs. The effects of lower temperatures and reduced maturation are more pronounced in the basins to the west than in the basins to the east, which the slab has not reached. If the transformation ratio is in the range 60-90%, as modelled, the Leeward Antilles basins offer good exploration opportunities. © 2013 EAGE.
Tukhvatullina R.R.,Roxar |
ECMOR 2012 - 13th European Conference on the Mathematics of Oil Recovery | Year: 2012
Acid treatment of the bottom hole formation zone is successfully applied in oil industry to increase well production rates. The value of permeability of the bottom hole zone strongly depends on well production. Acid impacts on porous media and it increases the permeability in a neighbourhood of well. The simulation of the effect of acid injection on permeability evolution is an important task, which demands accounting of various physical phenomena in bottom hole zone. Solution is based on the numerical consideration of the mathematical model of chemical reaction in carbonate reservoir. The main aim of this study is to estimate influence of the Carbon-dioxide gas, which is one of the chemical reaction products, on the permeability of bottom hole zone and well skin-factor. Twodimensional model of two-phase flow of acid aqueous solution and gas is considered.This phenomena has effect on acid filtration in porous media and it takes into account in numerical simulation. It is shown that in some important cases neglecting of gas phase leads to significant errors in estimation of parameters of bottom hole zone.Well skin-factor after acid treatment is calculated as a function of acid volume and injection time.