Integrated characterization of the Upper Permian Kapp Starostin Formation in central Spitsbergen, Svalbard. From outcrop to geomodel.

Abstract

Natural fractures significantly contribute to improved reservoir quality and recovery factor, especially in carbonate reservoirs. It is important to characterize the matrix and fracture properties, as well as their interaction, in order to describe the natural fracture system and improve the understanding of its effects on a reservoir. This study integrates multi-scale outcrop data from central Spitsbergen, Svalbard, to assess the impact of fractures on the reservoir potential of the Upper Permian Kapp Starostin Formation, considered as an analogue for a fractured carbonate reservoir.A combination of traditional field methods and digital geology methods was applied to analyze and characterize natural fractures. The methods include scanline measurements (~16 m), the use of the Fieldmove Clino smartphone app, photogrammetry, virtual scanlines (~2611 m) and analysis of a total of 10 virtual models. Sedimentary logging was conducted to link the fractures to 12 distinct sedimentary facies and consider their rheological effects. The 245 m long composite log indicates that the section mainly consists of light and dark spiculitic cherts with smaller units of limestones, black shales and glauconitic sandstones. Matrix porosity was derived from thin section analyses. These indicate porosities up to 30 % in the glauconitic sandstones and light spiculities, whereas the dark spiculites and limestones show 0-5 %. A total of 7 fracture sets (F1-F7) have been identified within the different facies. Most fractures are high-angled (>60°) and striking NW-SE to NNE-SSW and NE-SW to E-W, as a result of several tectonic events. These events include; (i) Early Cretaceous extension and tectonic movements along the Billefjorden Fault Zone (ii) transpressional tectonics in the Paleogene, (iii) rotation of the horizontal compression from NE-SW to ENE-WSW later in Paleogene, and (iv) Cenozoic uplift and unloading. Fracture characterization suggests that mechanical properties and lithology mainly control the fracture density. Fracture geometry and distribution are controlled by sedimentology and diagenesis. Based on the results, a conceptual fracture model has been constructed to explain the fracture development within the Kapp Starostin Formation in central Spitsbergen. Observations in this study suggest that most fractures are open or partly filled and can therefore act as conduits for fluid flow. The fractures are interpreted to be of tectonic origin, but the strata are also highly affected by diagenetic fractures and veins that originated during early burial and deposition. All data obtained in field were used as input for discrete fracture network (DFN) modelling. The generated models provide constraints on how fracture properties, such as fracture density, length and aperture, influence fracture porosity and connectivity. DFN modelling of fracture porosity suggests that the fracture porosity is highly sensitive to changes in fracture aperture and density, whereas the fracture length shows no significant impact. Fracture connectivity is dependent on changes in fracture density and did not show any effect with changing fracture aperture. Parts of the Kapp Starostin Formation are interpreted as a type I or II reservoir where porosity and permeability are fully or partly provided by the fracture network. I conclude that the upper part of the Kapp Starostin Formation could represent a suitable reservoir and that the exploitation of outcrop data provides an improved understanding of the heterogeneous fracture characteristics in a subsurface reservoir