Evaluating Petrophysical Properties and Volumetrics Uncertainties of Sand Injectite Reservoirs – Norwegian North Sea

Sand injectites on the Norwegian Continental Shelf have proven their commercial significance. Some are already producing, e.g., Volund, Viper, Balder, Ringhorne, and Kobra Fields, while others such as in production licenses (PL) 340 and 869 have recently been discovered and appraised. Extensive literature on the geology of sand injectites has been published (e.g., Jenssen et al., 1993; Jolly and Lonergan, 2002; Huuse et al., 2003; Hurst et al., 2005). However, few references are available on the petrophysical and geophysical aspects of sand injectite reservoirs. This paper discusses the petrophysical properties of sand injectite facies, dykes, sills, and brecciated sands, along with their identification from seismic data. A perception that volumetrics of sand injectite reservoirs cannot be reliably evaluated is assessed. Sand injectites in PL 340 and 869 were interpreted as remobilized sands from the Hermod and Heimdal Formations of Paleocene age injected into the overlying Balder Formation and Hordaland Group mudstones of Eocene age. The mudstones acted as a seal, forming an intrusive stratigraphic trap. The trap geometry varied locally depending upon the dyke and sill geometries of the sandstone. Dykes had large vertical reach with the corresponding high-hydrocarbon column, while sills had low-vertical relief with large lateral extent. Intervals of brecciated sands were also observed within the injectite complex, especially where sands were thin. These brecciated sands contained large amounts of angular mudstone clasts of different dimensions suspended in an overall sandy matrix. Close examination of cored dykes made it possible to observe this, while it might not be as obvious when looking at bulk well logs. Petrophysical-log responses for clean sills and dykes behaved the same way as they would in a clean sandstone reservoir. If sills and dykes were very thin, they would also risk not being counted as net or pay (Suau et al., 1984; Dromgoole et al., 2000; Flølo et al., 2000;). Such errors can impact in-place volumes in a significant way. Sills appeared as blocky clean sand on logs, but it was difficult to differentiate a dyke from a sill or thin sands using logs. Dykes are high-angle features and are identified either by core studies or borehole images when intersected by a well or, if large enough, observable on seismic. Brecciated sand intervals appeared with cm-to-dm-scale mudstone clasts suspended in sand with approximately 40 to 60% net to gross. Log responses over these intervals indicated shaly sand or thin sands. Resistivity and thermal neutron porosity logs were highly affected by the shale clasts. For this reason, a fractional net/gross interpretation technique was used to evaluate the sand content and hydrocarbon pore volume. To further verify these results, they were compared to observations directly on the core. To qualify to what extent petrophysical logs and interpreted products thereof can be relied on to evaluate hydrocarbon volumes of sand injectite reservoirs, a high-resolution petrophysical interpretation was generated using a computerized tomography (CT) scanned core image. Core image sand counting and image-derived high-resolution bulk density logs with shale-corrected resistivity were used. Results of this high-resolution interpretation featured an excellent match with routine core analysis data and manual core observations in the core laboratory. The fractional net/gross method used is the modified Thomas-Stieber method (Johansen et al., 2018). Its results compared well to the high-resolution CT-scan image results and better evaluated the hydrocarbon pore volume of sand facie compared to the conventional bulk formation evaluation approach. This result confirms that the Thomas-Stieber method can be used for brecciated rocks, which leads to some useful recommendations on how to best log and perform a petrophysical evaluation in such reservoirs.