Self-Organizing-Map Approach Characterizes Naturally Fractured Reservoir in a Mature Field

Abstract

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 206027, “Naturally Fractured Basement Reservoir Characterization in a Mature Field,” by Muhammad Nur Ali Akbar, MOL Hungary. The paper has not been peer reviewed. The complete paper describes an alternative solution for identifying the presence of natural fractures, classifying them into fracture-quality-related flowability, and distributing them vertically within the well interval, and proposes a lateral distribution method for reservoir modeling. The proposed approach, using the machine-learning technique of self-organizing-map (SOM) clustering, effectively assists recognition of fracture presence and quality along the well-depth interval. Field Overview and Data Used The case study was conducted in an oil field discovered in the early 1980s in southwestern Hungary. Thirty-six wells penetrated the naturally fractured carbonate in the Triassic formation. The main lithology of this reservoir is limestone and dolomite associated with faults and exhumation breccia and marl/shale. The reservoir is saturated oil (with gas cap) with unlimited aquifer (strong water drive). The gas cap, however, is mainly composed of 85% carbon dioxide and up to 1,800 ppm of hydrogen sulfide. Generally, the oil is intermediate to heavy, with a gravity of approximately 20 °API. The reservoir rock properties of this case study are fully complex for both the pore system and its composition. In general, the matrix pore system does not significantly contribute to storativity or permeability. The effective porosity is approximately 4.2% on average. This value sometimes directs to the matrix porosity, but in this case study, high intensity of the microfracture presence behaves in a way similar to matrix porosity, a phenomenon the author terms “pseudomatrix porosity.” Moreover, the effective oil permeability value of the studied fractured reservoir is extremely high (up to 70 darcies per well-test interpretation). The permeability ranges from 1 to 2000 md in brecciated fractures or in naturally fractured rock samples. Two types of core samples were used in this study—fractured breccia and naturally fractured rock. Both types have similar behavior in terms of the porosity/permeability relationship. In this study, that relationship is not the one normally observed in clastic reservoir rock. Marl/shale content is one of the more- critical parameters, indicating low fracture quality in terms of permeability. More than 50% of the well-log data for this study were measured by Russian-type well logs, meaning that only simple electrical, gamma ray, and neutron- capture gamma logs were available. Other wells have standard triple-quad combination logs. Image logs are available only from two wells drilled in the 2000s. By considering these log-data limitations, cores, and production-test results, the study aimed to define the effective fracture locations and intervals.