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History Matching Channelized Facies Models Using Ensemble Smoother With A Deep Learning Parameterization
- Publisher: European Association of Geoscientists & Engineers
- Source: Conference Proceedings, ECMOR XVI - 16th European Conference on the Mathematics of Oil Recovery, Sep 2018, Volume 2018, p.1 - 21
Abstract
Ensemble data assimilation methods have been successfully applied in several real-life history-matching problems. However, because these methods rely on Gaussian assumptions, their performance is severely degraded when the prior geology is described in terms of complex facies distributions. This work introduces a novel parameterization based on deep learning for history matching facies models with ensemble methods.
The proposed method consists on a parameterization of geological facies by means of a deep belief network (DBN) used as an autoencoder. The process begins with a large set of facies realizations which are used for training the DBN. The trained network has two parts: an encoder and a decoder function. The encoder is used to construct a continuous parameterization of the facies which is iteratively updated to account for observed production data using the method ensemble smoother with multiple data assimilation (ES-MDA). After each iteration of ES-MDA, the decoder is used to reconstruct the facies realizations.
The proposed method is tested in three synthetic history-matching problems with channelized facies constructed with multiple point geostatistics. We compare the results of the DBN parameterization against the standard ES-MDA (with no parameterization) and the recently proposed optimization-based principal component analysis (OPCA). Our results show that all procedures are able to match the observed production data. However, standard ES-MDA failed to generate channel facies with well-defined boundaries. OPCA and DBN parameterizations improved the facies description resulting in the expected bi-modal distributions of log-permeability. This paper reports our initial results on an ongoing investigation with deep learning. Nevertheless, the results presented here indicate a great potential on the use of deep learning technologies in the inverse modeling of petroleum reservoirs.