This report describes the activities performed within Task 1.2 “Report on gas solubility and degassing kinetic (type C)” until the end of month 40 of the REFLECT project. Two series of experiments have been carried out that assess the degassing process of type C geothermal fluids respectively in bulk and porous media. This has resulted in an improved understanding of the process and the associated physical phenomena by utilizing experimental equipment and data analysis tools specifically created for this task.@en

The exsolution of gas molecules from gas–liquid mixtures plays a significant role in a wide range of applications from industrial processes such as metal casting to subsurface flow of oil or geothermal waters. This study aims to improve the understanding of the conditions under which free gas bubbles start forming in CO2–water mixtures. The bubble point pressure was determined under various different conditions like the temperature and initial pressure of the mixture along with other parameters such as the bubble growth rate. A series of depressurization experiments at high pressure and temperature (up to 100 bar and 100 °C) is performed using a pressure cell that allows for visual monitoring of the degassing process. Bubble formation during the depressurization process is recorded using a high-speed camera paired with a uniform light source along with a pressure transducer and thermocouple. Image analysis allows for the determination of the bubble point pressure and rate of bubble formation. For CO2 in its gaseous state and at moderate temperatures, decent agreement between experimental results and the theoretical bubble point pressure is found, although significant deviations are observed at elevated temperatures. More pronounced differences in bubble point are observed for mixtures starting out at high pressures where CO2 is a supercritical fluid, which lead to lower than expected bubble point pressures.@en

The long-term performance of the reservoir is essential in order to ensure competitive life-cycle cost of the geothermal installations. Geothermal fluids are often saturated with gasses such as CO2 and N2. With their extraction from the reservoir, pressure and temperature decrease towards the extraction well. This disturbs the state of equilibrium the geothermal water is in with its dissolved components, which for gas can lead to exsolution. The exsolved gas bubbles can block the pores of the reservoir rock and therefore reduce the apparent permeability. As permeability reduction occurs mainly near the extraction well it can reduce production of geothermal waters substantially. This paper is aimed at experimentally investigating the conditions at which the onset of degassing starts and quantitively assess any associated permeability decrease. Knowledge on these parameters will enable operators to adapt their operation procedures in order to ensure long-time reservoir permeability. This paper reports core-flood experiments where tap water containing dissolved carbon dioxide was injected into either a Bentheimer (2.3 Darcy) or Berea (140millidarcy) sandstone core at different conditions. The first sets of core-flood experiments showed that at a temperature of 30 °C and pressure up to 50 bars the onset of the degassing process correlates closely to CO2solubility values obtained by the Henry’s law. At these conditions CO2 degassing near the core outlet will cause the apparent permeability to decrease by a factor2 to 5 in the high permeability Bentheimer sandstone core. At the same conditions the apparent permeability will decrease by a factor of nearly 10 in the low permeability Berea sandstone core. The decrease ineffective permeability is gradual in the Bentheimer sandstone while in the Berea sandstone the change is steeper. For rocks with small pore sizes and low absolute permeability, the reduction in effective permeability is larger and the rate of permeability decrease is faster. However, the onset of degassing is not influenced by the pore size and initial permeability. Experiments at temperatures between 30 and 90 °C show that with increasing temperature, the Van ‘t Hoff equation becomes less to accurate to find the degassing pressure@en

Foam is used in gas-injection EOR processes to reduce the mobility of gas, resulting in greater volumetric sweep. SAG (Surfactant Alternating Gas) is a preferred method of injection as it results in greater injectivity in the field, but designing a successful process requires knowledge of foaming performance at very high foam qualities (gas fractional flows). Here the use of foam in low-permeability (∼1 mD) Indiana Limestone cores for SAG foam applications is studied. Coreflood experiments were performed for a range of foam qualities at high pressure (100 bar), elevated temperature (55 °C), high salinity (200,000 ppm) and in the presence of crude oil. The effectiveness of the foam was studied by differential pressure measurements along the core. Foam was still able to form under these stringent conditions, but it was a relatively weak foam (i.e. its ability to reduce gas mobility is modest). For one surfactant formulation, further analysis of the experimental results show that the foam would be able to maintain mobility control over the displaced phase, thus providing a stable displacement front, and that it can be used in a SAG foam process in these formations. For a second formulation the non-monotonic nature of the fractional-flow data requires further investigation before scale-up to the field. In addition, further coreflood experiments were carried out using heterogeneous, vuggy Edwards White cores with even lower permeability (∼0.5 mD). These experiments were performed to determine whether foaming is possible in heterogeneous media and especially to investigate the effects of disconnected vugs on the foaming performance. CT scans were taken during the period of foam injection to determine saturation profiles within the core. Foam was able to form inside these cores, but inside the vugs segregation was observed with liquid pockets visible in the bottom of the vugs and gas in the remainder. This segregation was only a local effect though, confined to the vug itself, and foam was able to persist in the rest of the core.

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Foam is used in gas-injection EOR processes to reduce the mobility of gas, resulting in greater volumetric sweep. SAG (Surfactant Alternating Gas) is a preferred method of injection as it results in greater injectivity in the field, but designing a successful process requires knowledge of foaming performance at very high foam qualities (gas fractional flows). Here the use of foam in low-permeability (~1 mD) Indiana Limestone cores for SAG foam applications is studied. Coreflood experiments were performed for a range of foam qualities at high pressure (100 bar), elevated temperature (55°C), high salinity (200,000 ppm) and in the presence of crude oil. The effectiveness of the foam was studied by differential pressure measurements along the core. Foam was still able to form under these stringent conditions, but it was a relatively weak foam (i.e. its ability to reduce gas mobility is modest). For one surfactant formulation, further analysis of the experimental results show that the foam would be able to maintain mobility control over the displaced phase, thus providing a stable displacement front, and that it can be used in a SAG foam process in these formations. For a second formulation the non-monotonic nature of the fractionalflow data require further investigation before scale-up to the field. In addition, further coreflood experiments were carried out using heterogeneous, vuggy Edwards White cores with even lower permeability (~0.5 mD). These experiments were performed to determine whether foaming is possible in heterogeneous media and especially to investigate the effects of disconnected vugs on the foaming performance. CT scans were taken during the period of foam injection to determine saturation profiles within the core. Foam was able to form inside these cores, but inside the vugs foam segregation was observed with liquid pockets visible in the bottom of the vugs and gas in the remainder. This segregation was only a local effect though, confined to the vug itself, and foam was able to persist in the rest of the core.

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A surfactant-screening methodology for foam enhanced oil recovery (EOR) is proposed that comprises both bulk-foam tests and foam flooding in model porous media. The initial foam screening (bulk-foam stability in test tubes) is aimed at quickly providing a qualitative indication of a surfactant’s foaming potential as well as salinity and oil tolerance at reservoir temperature. Surfactant formulations passing these tests are tested further in a series of foam-flooding experiments in model porous media (bead packs) under reservoir conditions (100-bar backpressure, at 55°C) at 95% gas fraction, with and without crude oil (32°API) present. The mobility-reduction factor (MRF) (i.e., ratio of pressure drop across the pack with foam compared with that for water) is a direct measure of foam strength in porous media. To investigate the effect of wettability, tests are performed in both strongly water-wet (glass beads) and oil-wet (polypropylene beads) porous media. The bulk-foam tests screened out most of the considered surfactants. Out of 31 surfactants tested, 26 precipitated in the highest-salinity brine (200,000 ppm). Also, the presence of crude oil resulted in foam collapse for most surfactants in the bulk tests. Surfactants that retained some foam stability in the presence of oil were carried forward to the porous-media tests. In our study, qualitative foam stability inferred from the bulk-foam-stability tests correlated well with the MRF in the water-wet bead packs. We found large variations in MRF comparing different surfactants; some have MRFs on the order of 10 and others are as high as 1,000. For all investigated surfactants, the presence of crude oil reduced MRF, but for some mobility reduction was still significant. The bulk-foam tests showed similar results, with foam retaining some stability even in the presence of oil for the surfactants that were analyzed in both bulk form and in porous media. Oil-wetness was found to have a detrimental effect on foam strength: Values of MRF were approximately one order of magnitude lower than those measured in the water-wet porous media. However, the decrease in MRF was not the same for all surfactants. The best-performing surfactant in the oil-wet pack was not the same as the best performer in the water-wet pack, proving the value of these additional tests. The goal of the protocol is to obtain a method for rapid testing the foaming performance and stability of a range of surfactants under conditions that are as realistic as possible. The most-promising surfactant(s) identified by use of this protocol are then selected to be evaluated further in long consolidated cores. @en