Abstract
Summary Carbonate-based mineral dissolution and precipitation, driven by carbon dioxide (CO2) injection, introduces complexities to carbonate reservoir systems that trigger interactions different from those seen in traditional CO2-enhanced oil recovery (CO2-EOR) applications in siliciclastic/sandstone reservoirs. The thrust of this paper is to couple experimental (laboratory-scale) and numerical (computationally-assisted) analyses in order to assess how CO2-induced petrophysical alterations impact the resultant hydrocarbon recovery from CO2-EOR applications in carbonate reservoirs. The Upper Red River Formation, located in North Dakota’s Cedar Creek Anticline (CCA) Field, presents significant remaining oil in place (OIP), albeit with a high water saturation from waterflood operations undergoing since the 1960s. The residual oil saturation (post-waterflooding) makes the Upper Red River Formation a good target for modern-day CO2-EOR technology. The first part of this study involves a core-scale investigation of dynamic-permeability variations triggered by the CO2 injection into three primary-productive zones, designated as “Red River Units” (RRU2, RRU4, and RRU6). The second part involves a compositional reservoir model used to perform numerical simulations of CO2 injection incorporating pre-established dynamic-permeability variations that honor the laboratory-obtained results. Correlations between differential-pressure variations observed during carbonated brine (CO2/brine mixture) injection were assessed against pore volumes injected (PVI). These pressure fluctuations were induced by dynamic-permeability variations resulting from carbonate-based mineral dissolutions/precipitations. Baseline-permeability variations were established a priori using nitrogenated-brine (N2/brine) injection to correct for physicochemical effects from the brine. During CO2/brine injection, the recorded permeability increased significantly compared to its original value, peaking before sharply decreasing. Inductively coupled plasma optical emission spectrometry (ICP-OES) and scanning electron microscopy (SEM) were utilized for deciphering the triggers of these dynamic-permeability variations, which revolve around mineral dissolutions and precipitations following the carbonate rock’s exposure to CO2. The history-matched compositional reservoir model was used to project the incremental production from CO2-EOR through a section incorporating four existing wells, incorporating the laboratory-derived dynamic-permeability variations, yielding different results compared with “base case” simulations performed at constant permeability. Reduced reservoir permeability correlated with decreased oil recovery, emphasizing the significant impact of dynamic-permeability variations on CO2-EOR performance and hence the importance of their integration in fieldwide development analyses.
Published Version
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