Characterising brines in deep Mesozoic sandstone reservoirs, Denmark

The Danish subsurface contains several sandstone units, which represent a large geothermal resource (Vosgerau et al. 2016). Currently, only three geothermal plants are operating in Denmark, but several exploration licences are expected to be awarded in 2019. Geothermal energy is exploited from deeply buried porous sandstones by bringing warm form­ation water (brine) to the surface, extracting the heat and returning the cooled water to the same sandstones. The reduced temperature of the brine during this process implies a risk of scaling, which may reduce reservoir permeability and hence injectivity. Predicting the chemical composition of formation waters, however, could help to reduce the risk associated with scaling in planned geothermal facilities. Here, we present a regional overview of the geochem­istry of brines from deep Mesozoic sandstones in the Danish Basin and North German Basin that supplements previous studies, notably by Laier (2002, 2008). The brine composition at shallow burial typically reflects the original (connate) formation water chemistry, which is determined by the original depositional environment of the sandstone, for example fluvial or marine. However, the mineralogical composition of the sandstone changes during burial, whereby some minerals may dissolve or precipitate when exposed to higher temperatures. These mineral changes are reflected in the brine composition, which typically becomes more saline with increased burial (e.g. Laier 2008; Kharaka & Hanor 2003).  The brine chemistry reported here shows a distinct depth trend, which reflects original connate formation waters that are modified through burial diagenesis. We have classified the brines into brine types, which are shown to be related to their depositional environment, depth, geological formation and geographical domains. ---------- There was an error published in GEUS Bulletin 43 (article 201943-01-04; DOI: 10.34194/GEUSB-201943-01-04). Tables 1 and 2 contained typesetting errors. The original and corrected data are listed below. All formats of this article have been updated (October 2022). The authors and editorial team apologise to readers for this error, which does not impact the overall results or conclusions of this paper. Table 1: Ca:Cl original: 00.04; 00.08; 00.04; 00.16; 00.16; corrected: 0.04; 0.08; 0.04; 0.16; 0.16 ; pH original: 06.06; 06.03; 05.09; 06.03; corrected: 6.6; 6.3; 5.9; 6.3 Table 2: Anhydrite original: 00.35; corrected:0.35; Halite original: 00.39, 00.03; corrected:0.39, 0.03; Barite original: 00.40, 00.03; corrected: 0.40, 0.03; Celestite original: 00.08, 00.04; corrected: 0.08, 0.0

Types of formation water and produced water in Danish oil- and gasfields: implications for enhanced oil recovery by injection of ‘smart’ water

Injection of chemically tuned, ‘smart’ water in oil reservoirs may increase both oil recovery rates and the total recovery (e.g. Morrow & Buckley 2011; Austad 2013; Zeinijahromi et al. 2015). This kind of water management has gained increased importance in the Danish North Sea reservoirs due to decreasing sweep efficiency in maturing oilfields. Knowledge about the compatibility of the injected water with local formation waters is, however, a prerequisite for successful implementation. Here, we present a regional overview of formation waters from oil reservoirs in the Danish North Sea, which comprise three main types of formation brine, and one type of modified seawater related to extensive water flooding. The water types show a distinct geographical distribution, which reflects original connate waters that are modified by saline brine being either depleted or enriched in SO42–.  &nbsp