Abstract
Core rock-typing (RT) is commonly used for creating geologically reliable models of porous media in carbonate reservoirs. This approach is more advanced than the traditional porosity–permeability relationship and is based on the division of carbonate rocks into groups, using common classifications (lithofacies, FZI, Winland–Pittman, etc.). These clustering methods can provide either geological or petrophysical descriptions of the identified rock types. Besides, the connection of identified core rock types with standard logs could be challenging due to the different scales of measurement. This paper considers the creation of a new approach, named “integrated rock-typing,” which connects geologically and petrophysically driven rock types using borehole image logs. The methodology was applied to an Upper Devonian–Lower Carboniferous carbonate field. The workflow comprises borehole image structural/textural analysis with vug fraction identification, quantitative geological descriptions from thin sections, and petrophysical measurements. The geological section is divided into six rock types, which were controlled by sedimentary and diagenetic processes. The created Rock Type Catalogue provides clear links between rock types and log data, including wells with standard suites of logs. The results will be useful for geological modelling and validation of the future drilling strategy for the studied field.
Highlights
Carbonate reservoir rocks are primarily represented by limestones and dolomites and characterized by complex pore networks, which can be created by a combination of different grain types, grain textures, mineral compositions, and diagenetic processes
The present study considers the integration of geological and petrophysical data to improve reservoir characterization for a real carbonate field with limited availability of core and logs
The proposed workflow is valuable in carbonate fields with limited data on core extracted and formation microimagers (FMI)
Summary
Carbonate reservoir rocks are primarily represented by limestones and dolomites and characterized by complex pore networks, which can be created by a combination of different grain types, grain textures, mineral compositions, and diagenetic processes. Later diagenetic processes and tectonic movements may have a significant influence on porosity and permeability by the formation of secondary porosity, including fractures, molds, and vugs. The dissolution of calcite can significantly increase the porosity in limestones and open natural fractures can create a connected system in low-porosity carbonates, allowing hydrocarbons to flow [1]. Poor correlation between reservoir porosity and permeability caused by its strong vertical and lateral heterogeneity, characterizing the carbonate reservoir and building the permeability model, is challenged [2]. Standard permeability models based on k–φ (permeability– porosity) relationships often do not support the creation of reliable geological models to be used for reservoir property predictions
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