Publication Date:
2020-02-12
Description:
Current secondary oil recovery measures allow for the recovery of a maximum of about 33 % of the oil in a reservoir. The remaining almost two third of the energy carrier are lost due to decreasing pressure, pore blocking, water inva- sion or hydrocarbon fluid adhesion to the rock. Therefore, fluids weakening the adhesion of hydrocarbons to pore walls and increasing permeability of the rock by e.g. mineral cement dissolution, are injected to the deposits in order to augment production. All such measures however, including enhanced oil recovery (EOR) methods such as the injection of supercritical CO2 may increase the recovery factor of the original oil in place by further 10 % only. Consequently, most of the hydrocarbon wealth in oil and gas reservoirs cannot be extracted and is lost to future generations. It is thus of high importance to understand the fundamental wetting processes in the pore space, to better develop the potential of oil and gas production from reservoir rocks and to secure the fossil energy supply. In siliciclastic oil and gas reservoir rocks, the pore space typically faces mineralogically varying sedimentary grains and various diagenetic minerals. Most common are mineral surfaces of quartz, feldspar, phyllosilicates, carbonates and iron oxides and hydroxides. This mineralogy surrounding the pore space, and the surface chemistry, topography and roughness on the micro and nano-scale rule the wetting behavior and adhesion properties of hydrocarbon fluids, water, or CO2 to the pore walls. The dispersion, migration, adhesion and reactivity of fluids in rocks depends also on pressure and temperature conditions, nevertheless, particularly the morphology of pore walls and the pore and pore-throat shapes, have a significant impact on the behavior of the water-gas contact depth (WGC) and on the potential recovery of hydrocarbons from the given reservoir rock. Each episode of fluid transport through the rock leaves a significant and characteristic trace in cement mineralogy, pore morphology, permeability, but often also in sediment grain or bioclast alteration. Such processes can be defined down to the nanoscale and play a crucial role in further mobility of hydrocarbons in rocks (Hassenkam et al., 2009). Sediment wetting varies with the alteration of the surfaces and depends on surface roughness, surface charges, and the chemical composition of the liquid phase (Al-Futaitsi et al., 2003; Al-Futaisi and Patzek, 2004). The interfacial tension of the fluids strongly depends on the composition of the coexisting phases (Sutjiadi-Sia et al., 2008). In addition, the presence of a supercritical (sc)CO2 phase can affect the wetting properties of the other phases due to mass exchange as a function of pressure (Foullac et al., 200; Sutjiadi-Sia et al., 2008; Jäger and Pietsch, 2009). It is, however, not clear how the specific conditions of the reservoir (p, T, surface chemistry and morphology) affect the interfacial tension of the relevant fluids. To understand the fundamental physico-chemistry helps to design new technologies for tertiary exploitation measures and for CO2-storage (Carbon Capture and Storage: CCS). In this project we investigate the relationship between various minerals or grains facing the pore space, to fluids in reservoir rocks and to CO2 and scCO2 (Altermann et al., 2008). In the following we report on the geological and physical characterization of the reservoir rock under investigation and on the characterization of wetting of rough model surfaces in scCO2.
Language:
English
Type:
info:eu-repo/semantics/conferenceObject
Format:
application/pdf
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