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Collaborating Authors
Results
New Insights Into CO2 Injection and Storage in Saline Aquifers
Sohrabi, Mehran (Centre for Enhanced Oil recovery and CO2 Solutions, Heriot-Watt University, Edinburgh) | Riazi, Masoud (Centre for Enhanced Oil recovery and CO2 Solutions, Heriot-Watt University, Edinburgh) | Bernstone, Christian (Vattenfall Research and Development) | Jamiolahmady, Mahmoud (Centre for Enhanced Oil recovery and CO2 Solutions, Heriot-Watt University, Edinburgh) | Christensen, Niels-Peter (Vattenfall Research and Development)
Abstract Worldwide, significant efforts and resources are being directed at evaluating potentials of CCS (carbon capture and storage) for the long term storage of large quantities of CO2 that would otherwise be released in the atmosphere. Despite many years of experience with CO2 injection in oil reservoirs, our current understanding of brine/CO2 interactions that occur during CO2 injection in aquifers (brine-bearing rocks) remains very limited. This is a source of uncertainty and concern not just for the governments and companies interested in investment in CCS but also for the public in relation to the safety of long term injection and storage of CO2 in geologic formations. In this paper we report new insights into the pore-scale interactions between super-critical CO2 and brine obtained from the results of a series of CO2 injection visualisation experiments carried out in novel high-pressure transparent porous media. In these experiments, we have physically simulated and visually investigated the micro-scale behaviour of CO2 in brine-bearing porous media. In particular, through vivid images of fluids distribution taken during the experiments, we highlight a new mechanism in which CO2 evolution follows CO2 dissolution in brine. In parts of the porous medium in which CO2 injection was taking place, it was observed that a free CO2 phase nucleated and came out of solution and gradually expanded. The phenomenon accelerated when the brine salinity increased or when the CO2 injection rate increased. The observed mechanism is expected to affect many important aspects of CO2 flow and retention in porous media. It may increase CO2 storage capacity by displacing more brine. On the other hand, it can adversely affect the ability of rock to safely contain the stored CO2.
- Europe (0.46)
- North America > United States (0.29)
Experimental and Theoretical Investigation of Gas/Oil Relative Permeability Hysteresis under Low Oil/Gas IFT and Mixed-Wet Conditions
Fatemi, S. Mobeen (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University, Edinburgh, UK) | Sohrabi, Mehran (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University, Edinburgh, UK) | Jamiolahmady, Mahmoud (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University, Edinburgh, UK) | Ireland, Shaun (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University, Edinburgh, UK)
Abstract Accurate determination of relative permeability values and their hysteresis is crucial for obtaining a reliable prediction of the performance of water-alternating-gas (WAG) injection in oil reservoirs. In this paper we report two series of gas/oil relative permeability curves obtained from coreflood experiments carried out in a mixed-wet core under a very low oil/gas interfacial tension (IFT) of 0.04mN.m. The first set of the corefloods began by oil injection (imbibition) in the core saturated with gas and immobile water (Swi). This was followed by a period of gas injection (drainage) and this sequential injection of oil and gas continued and in total, three imbibition and two drainage periods were carried out. In the second series of experiments, the core was initially saturated with oil and immobile water and the experiment started with a gas injection followed by cycles of drainage and imbibitions. The measured pressure drop and production data were history matched through simulation analysis to obtain krg and kro values for each of the imbibition and drainage cycles. The results show that both the oil and the gas relative permeability curves show cycle-dependent hysteresis despite the very low gas/oil IFT. Therefore, the current assumption in existing models (such as Land, Carlson and Killough) that the drainage scanning kr curves follow the preceding imbibition curve is not supported by our coreflood experiments. When compared to our measured data, Carlson model predictions for krg in imbibition direction are poor. Killough model predictions underestimate krg and overestimate kro especially near trapped gas saturation regions. Beattie et al. hysteresis model is able to capture the krg and kro behavior that we observed in our experiments qualitatively, but it is still unable to predict the value of the observed hysteresis. The results suggest that for mixed-wet systems, it is necessary to consider irreversible hysteresis loops for both the wetting and non-wetting phases. Such capability currently does not exist in reservoir simulators due to lack of appropriate predictive tools.
- North America > United States (1.00)
- Europe (1.00)
- Research Report > New Finding (0.86)
- Research Report > Experimental Study (0.68)
Abstract The main purpose of applying surfactants for hydraulically fractured wells is to reduce fracturing fluid surface tension during the leak-off process and hence improve its cleanup efficiency. Significant research has been devoted to developing such chemicals that can effectively reduce capillary forces between fracture fluid and resident rock and fluids. However, in a recent numerical study (SPE-14414), we have shown that, for some cases, reducing surface tension tends to decrease the cleanup efficiency. Following our previous study, we have conducted a comprehensive sensitivity study to identify conditions in which reduction of surface tension improves cleanup efficiency. During this exercise, the impacts of matrix permeability (km), fracture permeability (kf) and fracture fluid injection volume were investigated. Over 200 simulation runs were performed covering a wide range of variation of of these pertinent parameters for a single fractured well model. The results indicate that at the early stage of production the cleanup efficiency is relatively poor and almost independent of IFT, km and kf. At late stages of production and when kf is low, reducing surface tension decreases the cleanup efficiency. For high kf values, on the other hand, cleanup efficiency improves with such a reduction. For the cases with km values greater than 0.001, cleanup efficiency is more effective if IFT increases. Furthermore, as km decreases, the damage due to fracture fluid blockage becomes more severe. It is interesting to note that when km is less than 0.0001, cleanup efficiency always decreases with increasing surface tension, for all different kf values. The amount of gas production loss for such cases is relatively high, indicating the severity of fracture fluid damage for very tight gas reservoirs. Increasing the fracture fluid injection volume did not significantly change the above trend. The results presented here aim to help the industry in properly evaluating the added value of using surfactant to improve the cleanup process of the hydraulically fractured wells.
Recovery Mechanisms and Relative Permeability for Gas/Oil Systems at Near-miscible Conditions: Effects of Immobile Water Saturation, Wettability, Hysteresis and Permeability
Fatemi, S. Mobeen (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University, Edinburgh, UK) | Sohrabi, Mehran (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University, Edinburgh, UK) | Jamiolahmady, Mahmoud (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University, Edinburgh, UK) | Ireland, Shaun (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University, Edinburgh, UK)
Abstract Near-miscible gas injection represents a number of processes of great importance to reservoir engineers including hydrocarbon gas injection and CO2 flood. Very little experimental data is available in the literature on displacements involving very low-IFT (interfacial tension). In this paper, we present the results of a series of two-phase and three-phase gas injection (drainage) and oil injection (imbibition) core flood experiments for an gas/oil system at near-miscible (IFT= 0.04 mN.m) conditions. Two different cores; a high-permeability (1000 mD) and a lower permeability (65 mD) core were used in the experiments and both water-wet and mixed-wet conditions were examined. The results show that despite a very low gas-oil IFT, there is significant hysteresis between the imbibition and drainage oil and gas relative permeabilities (kr) curves in the 65mD core. Hysteresis was less for 1000mD core (compared to the 65 mD core) but it still could not be ignored. Near-miscible kr hysteresis was significant for both water-wet and mixed-wet systems. Presence of immobile water in the water-wet cores improved oil relative permeabilities but reduced gas relative permeabilities in both imbibition and drainage directions. As a result, oil recovery for gas injection experiments improved when the rock contained immobile water. Both oil and gas relative permeabilities reduced when the rock wettability was altered to mixed wet from water wet and as a result, oil recovery by gas injection in the mixed-wet rock was less than that obtained under water-wet conditions. We offer explanations for these observations based on our understanding of the pore-scale interactions and mechanisms, the distribution of fluid phases and their spreading bahaviour. The results help us better understand the impact of some of the important parameters pertinent to kr and its hysteresis especially in very low IFT gas-oil systems and mixed-wet rocks. Understanding these effects and behavior is important for improved prediction of the performance of gas injection and water-alternating gas (WAG) injection in oil reservoirs.
- North America > United States > California (0.46)
- North America > United States > Texas (0.28)
Visualization of Oil Recovery by CO2-Foam Injection; Effect of Oil Viscosity and Gas Type
Emadi, Alireza (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University, Edinburgh, UK.) | Sohrabi, Mehran (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University, Edinburgh, UK.) | Jamiolahmady, Mahmoud (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University, Edinburgh, UK.) | Ireland, Shaun (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University, Edinburgh, UK.)
Abstract CO2 injection is a well-established enhanced oil recovery technique which has been successfully applied in conventional oil reservoirs where it can vaporize light hydrocarbon components and displace the oil miscibly. In heavy oil reservoir, CO2 does not develop miscibility but it can significantly promote recovery by dissolving in the oil and reducing its viscosity. Heavy oil viscosity reduction upon mixing with CO2 can be substantial and reductions up to two orders of magnitude can be achieved. However, displacement of viscous and heavy oil by CO2 is generally perceived as being inefficient and hence, very limited number of heavy oil fields have been considered for CO2 injection. There are two main reasons for this; (1) the large viscosity contrast between heavy oil and CO2 which results in viscous fingering and; (2) the slow rate of CO2 diffusion in heavy oil. The use of CO2 foam represents an opportunity to reduce mobility of CO2 and improve sweep efficiency and at the same time facilitate CO2 dissolution by increasing the contact area between the oil and CO2. The application of foam injection for enhanced heavy oil recovery has not been widely reported in the literature and hence the potential of foam for improving heavy oil recovery is by and large untested. In our previous works, we reported a series of micro-scale visualization experiments to investigate potentials of sub- critical CO2 and CO2-foam injection for recovery of a medium-heavy crude oil. The results showed that if strong CO2-foam forms in porous medium, it can drastically increase the rate of oil recovery and reduce the residual oil saturation. This paper presents the results of a new series of visualization experiments to investigate the performance of sub-critical CO2-foam for recovery improvement in an extra-heavy crude oil. In the first part of this paper, the effect of oil viscosity on oil recovery and displacement mechanisms has been investigated. The results show that while foam can significantly accelerate and improve oil recovery by CO2 injection, the increase in oil viscosity slows down the process of oil recovery by CO2-foam and may result in weakening of some of the pore scale displacement mechanisms. In the second part of the paper, the results of an experiment conducted using the same extra-heavy crude oil and surfactant with N2-foam (instead of CO2) is presented. The results show that despite forming strong foam in the porous medium, the oil displacement process is much less efficient during N2-foam injection compared to CO2-foam. The results clearly demonstrate the potential of CO2-foam for enhancing heavy oil recovery for very viscous crudes as a technically viable non-thermal oil recovery method. The results of these experiments significantly improve our understanding of the processes involved in heavy oil recovery by CO2-foam and the pore scale differences with the example of N2-foam injection.