As part of the Synergetic Utilisation of CO (Formula presented.) storage Coupled with geothermal EnErgy Deployment project, investigating CO (Formula presented.) reinjection with different seismic methods, both passive and active seismic surveys have been conducted at the geothermal power plant at Hellisheiði, Iceland. During the 2021 survey, two geophone lines recorded noise for a week. We process the passive-source data with seismic interferometry to image the subsurface structure around the CarbFix2 reinjection reservoir. To improve image quality, we perform an illumination analysis to select only noise panels dominated by body-wave energy. The results show that most noise panels are dominated by air-wave energy arriving from the direction of the power plant. We use panels with a near-vertical incidence to create a zero-offset image and a larger selection of body-wave-dominated panels to create virtual common-shot gathers. We process the gathers with a simple reflection seismology processing workflow to obtain stacked images. The zero-offset images show a relatively lower signal-to-noise ratio and only horizontal reflectors. The stacked images show slightly dipping reflectors and possibly lateral amplitude variations around the expected injection region. This could indicate a region of interest for future research into the reinjection reservoir.

As part of a seismic monitoring project in a geothermal field, where the feasibility of re-injection and storage of produced CO₂ is being investigated, a P- and S-wave seismic velocity characterisation study was carried out. The effect of axial and radial (up to 42 MPa) stress, pore pressure (up to 17 MPa), pore fluid (100% brine or supercritical CO₂) and temperature (21–100 °C) on seismic properties were studied in the laboratory for the two main reservoir formations at the Kızıldere geothermal reservoir. Each (un)confined compressive strength test performed revealed a similar trend: rapidly increasing velocity at low stresses followed by a more moderate increase at higher stresses. The data implied that the stress-dependency of the velocity increased with temperature. Increasing temperatures resulted in decreasing P-wave velocities due to mineral thermal expansion. This temperature-dependency increased with reducing stress levels. The S-wave velocity seems to be more sensitive to changes in pore pressure than the P-wave velocity. On the other hand, the S-wave velocity is less affected by an increasing axial stress compared to the P-wave velocity. By performing multiple nonlinear regression on the velocity dataset, related to a brine-saturated fractured marble, second-degree polynomial trends were found for the P- and S-wave velocity, as a function of temperature, axial stress, and pore pressure, that can potentially be used for predicting velocities at Kızıldere, or other similar, geothermal site(s). For distinguishing between a 100% brine-saturated versus a fully supercritical CO₂-saturated fracture, the arrival times of the first arrivals were too close to each other to allow their utilization. The fracture aperture was too small compared to the wavelength of the source signal. However, differences in P- and S-wave amplitudes of the first arrivals were seen, where the supercritical CO₂-saturated crack revealed consistently lower peak and trough amplitudes compared to the brine-saturated scenario.

As part of a seismic monitoring project in a geothermal field, where the feasibility of re-injection and storage of produced CO₂ is being investigated, a P-and S-wave seismic velocity characterisation study was carried out. The effect of axial (up to 95 MPa) and radial (up to 60 MPa) stress on the seismic velocity was studied in the laboratory for a broad range of dry sedimentary and metamorphic rocks that make up the Kızıldere geothermal system in Turkey. Thin section texture analyses conducted on the main reservoir formations, i.e., marble and calcschist, confirm the importance of the presence of fractures in the reservoir: 2D permeability increases roughly by a factor 10 when fractures are present. Controlled acoustic-assisted unconfined and confined compressive strength experiments revealed the stress-dependence of seismic velocities related to the several rock formations. For each test performed, a sharp increase in velocity was observed at relatively low absolute stress levels, as a result of the closure of microcracks, yielding an increased mineral-to-mineral contact area, thus velocity. A change in radial stress appeared to have a negligible impact on the resulting P-wave velocity, as long as it exceeds atmospheric pressure. The bulk of the rock formations studied showed reducing P-wave velocities as function of increasing temperature due to thermal expansion of the constituting minerals. This effect was most profound for the marble and calcschist samples investigated.

History-matching of core-flood experimental data through numerical modeling is a powerful tool to get insight into the relevant physical parameters and mechanisms that control fluid flow in enhanced oil recovery processes. We conducted a mechanistic numerical simulation study aiming at modeling previously performed water-alternating-gas and foam-assisted chemical flooding core-flood experiments. For each experiment, a one-dimensional model was built. The obtained computed tomography scan data was used to assign varying porosity, and permeability, values to each grid block. The main goal of this study was to history-match measured phase saturation profiles along the core length, pressure drops, produced phase cuts, and the oil recovery history for each of the experiments conducted. The results show that, to obtain a good match for the water-alternating-gas experiment, gas relative permeability needs to be reduced as a function of injection time due to gas trapping. The surfactant phase behavior, for the aid of foam-assisted chemical flooding, was successfully simulated and its robustness was verified by effectively applying the same phase behavior model to the two different salinity conditions studied. It resulted in the oil mobilization, through the injection of a surfactant slug, being properly modeled. The mechanistic simulation of foam using the steady-state foam model built in UTCHEM proved inadequate for the mechanistic modeling of a foam drive in the presence of oil. An alternative heuristic approach was adopted to overcome this limitation.

The novel enhanced oil recovery (EOR) technique combining the reduction of oil/water (o/w) interfacial tensions (IFT) to ultralow values and generation of a foam drive for mobility control is known as foam-assisted chemical flooding (FACF). We present a well-controlled laboratory study on the feasibility of FACF at reservoir conditions. Two specially selected chemical surfactants were screened on their stability in sea water at 90 °C. The ability of both surfactants to generate stable foam in bulk was studied in the presence and absence of crude oil. It led to the composition of the foam drive formulation for drive mobility control. Phase behavior scan studies, for the two crude oil/surfactant/brine systems, yielded the design of the chemical slug capable of mobilizing residual oil by drastically lowering the o/w IFT. Core-flood experiments were performed in Bentheimer sandstones previously brought to a residual oil to waterflood of 0.33 ± 0.02. A surfactant slug at under-optimum (o/w IFT of 10^-2 mN/m) or optimum (o/w IFT of 10^-3 mN/m) salinity was injected for mobilizing residual oil. It resulted in the formation of an unstable oil bank because of dominant gravitational forces at both salinities. Next, a foam drive was generated either in situ, by co-injecting nitrogen gas and surfactant solution, or pregenerated ex situ and then injected to displace the oil bank. We found that (i) the presence of the crude oil used in this work has a detrimental effect on foam stability in bulk and foam strength in Bentheimer sandstones, (ii) optimum salinity FACF was able to increase the ultimate oil recovery with 5% of the oil in place (OIP) after water flooding compared with under-optimum FACF, and (iii) injection of pregenerated drive foam increased its ultimate oil recovery by 13% of the OIP after water flooding compared to in situ drive foam generation at optimum salinity.

A laboratory study of principal immiscible gas flooding schemes is reported. Very well-controlled experiments on continuous gas injection, water-alternating-gas (WAG) and alkaline–surfactant–foam (ASF) flooding were conducted. The merits of WAG and ASF compared to continuous gas injection were examined. The impact of ultra-low oil–water (o/w) interfacial tension (IFT), an essential feature of the ASF scheme along with foaming, on oil mobilisation and displacement of residual oil to waterflood was also assessed. Incremental oil recoveries and related displacement mechanisms by ASF and WAG compared to continuous gas injection were investigated by conducting CT-scanned core-flood experiments using n-hexadecane and Bentheimer sandstone cores. Ultimate oil recoveries for WAG and ASF at under-optimum salinity (o/w IFT of 10⁻¹ mN/m) were found to be similar [60 ± 5% of the oil initially in place (OIIP)]. However, ultimate oil recovery for ASF at (near-)optimum salinity (o/w IFT of 10⁻² mN/m) reached 74 ± 8% of the OIIP. Results support the idea that WAG increases oil recovery over continuous gas injection by drastically increasing the trapped gas saturation at the end of the first few WAG cycles. ASF flooding was able to enhance oil recovery over WAG by effectively lowering o/w IFT (< 10⁻¹ mN/m) for oil mobilisation. ASF at (near-)optimum salinity increased clean oil fraction in the production stream over under-optimum salinity ASF.

Alkaline/surfactant/foam (ASF) flooding is a novel enhanced-oil-recovery (EOR) process that increases oil recovery over waterflooding by combining foaming with a decrease in the oil/water interfacial tension (IFT) by two to three orders of magnitude. We conducted an experimental study regarding the formation of an oil bank and its displacement by foam drives with foam qualities within the range of 57 to 97%. The experiments included bulk phase behavior tests using n-hexadecane and a single internal olefin sulfonate surfactant, and a series of computed-tomography (CT) -scanned coreflood experiments using Bentheimer Sandstone cores. The main goal of this study was to investigate the effect of drive-foam quality on oil-bank displacement. The surfactant formulation was found to lower the oil/water IFT by at least two orders of magnitude. Coreflood results, at under-optimum salinity conditions yielding an oil/water IFT on the order of 10-1 mN/m, showed similar ultimate-oil-recovery factors for the range of drive-foam qualities studied. A more distinct frontal oil-bank displacement was observed at lower drive-foam qualities investigated, yielding an increased oil-production rate. The findings in this study suggested that dispersive characteristics at the leading edge of the generated oil bank in this work were strongly related to the surfactant slug size used, the lowest drive-foam quality assessed yielded the highest apparent foam viscosity (and, thus, the most stable oil-bank displacement), and drive-foam strength increased upon touching the oil bank when using drive-foam qualities of 57 and 77%.