An Improved Model for Geostatistical Simulation of Fracture Parameters and their Effect on Static and Dynamic Models
A.H. Etminan*, A. Seifi
Identifiers and Pagination:Year: 2008
First Page: 47
Last Page: 57
Publisher Id: TOPEJ-1-47
Article History:Received Date: 21/2/2008
Revision Received Date: 8/03/2008
Acceptance Date: 14/4/2008
Electronic publication date: 13/6/2008
Collection year: 2008
open-access license: This is an open access article distributed under the terms of the Creative Commons Attribution 4.0 International Public License (CC-BY 4.0), a copy of which is available at: https://creativecommons.org/licenses/by/4.0/legalcode. This license permits unrestricted use, distribution, and reproduction in any medium, provided the original author and source are credited.
This article presents a method for simulation of continuous and discrete fracture parameters distributions in hydrocarbon reservoirs using Sequential Indicator Simulation (SIS) and Sequential Gaussian Simulation (SGS) methods. Fracture parameters including azimuth, dip and density are integrated with the porosity and permeability values determined in the models. Based on this study we have identified stylolites, occluded fractures, vugs (isolated pores) and open fractures using core data from 13 wells in one of the southern Iranian gas fields. A model is constructed using SIS that contains fractures. This enables us to evaluate the role of fractures in the model enhancing permeability and their predictability in reservoirs. For this purpose, only the fractured blocks of the mentioned model were selected for fractures density, azimuth and dip modeling. Afterward, a novel function named Fracture Effect Factor (FEF) is introduced to calculate the effect of fractures on permeability model in the fractured blocks. For porosity modeling, fractures type model is used as an aid for increasing the accuracy of the modeling so that for the mentioned four fracture types, individual variograms are constructed and porosity estimation in each block is performed based on its related variogram. The proposed model is compared with dual porosity model on a fractured reservoir in South of Iran for a period of 18 years. The results of this research indicate that this method can visualize a more real estimation of dynamic and static behavior of the reservoir.