The energy transition is the pathway to transform the global economy away from its current dependence on fossil fuels towards net zero carbon emissions. This requires the rapid and large-scale deployment of renewable energy. However, most renewables, such as wind and solar, are intermittent and hence generation and demand do not necessarily match. One way to overcome this problem is to use excess renewable power to generate hydrogen by electrolysis, which is used as an energy store, and then consumed in fuel cells, or burnt in generators and boilers on demand, much as is presently done with natural gas, but with zero emissions. Using hydrogen in this way necessitates large-scale storage: the most practical manner to do this is deep underground in salt caverns, or porous rock, as currently implemented for natural gas and carbon dioxide. This paper reviews the concepts, and challenges of underground hydrogen storage. As well as summarizing the state-of-theart, with reference to current and proposed storage projects, suggestions are made for future work and gaps in our current understanding are highlighted. The role of hydrogen in the energy transition and storage methods are described in detail. Hydrogen flow and its fate in the subsurface are reviewed, emphasizing the unique challenges compared to other types of gas storage. In addition, site selection criteria are considered in the light of current field experience.
The growing demand for clean energy can be met by improving the recovery of current resources. One of the effective methods in recovering the unswept reserves is chemical flooding. Microemulsion flooding is an alternative for surfactant flooding in a chemical-enhanced oil recovery method and can entirely sweep the remaining oil in porous media. The efficiency of microemulsion flooding is guaranteed through phase behavior analysis and customization regarding the actual field conditions. Reviewing the literature, there is a lack of experience that compared the macroscopic and microscopic efficiency of microemulsion flooding, especially in low viscous oil reservoirs. In the current study, one-quarter five-spot glass micromodel was implemented for investigating the effect of different parameters on microemulsion efficiency, including surfactant types, injection rate, and micromodel pattern. Image analysis techniques were applied to represent the phase saturations throughout the microemulsion flooding tests. The results confirm the appropriate efficiency of microemulsion flooding in improving the ultimate recovery. LABS microemulsion has the highest efficiency, and the increment of the injection rate has an adverse effect on oil recovery. According to the pore structure’s tests, it seems that permeability has little impact on recovery. The results of this study can be used in enhanced oil recovery designs in low-viscosity oil fields. It shows the impact of crucial parameters in microemulsion flooding.
There are many uses of foam in petroleum industry yet there is no dependable industry standard on screening a wide variety of foaming surfactants available for a particular application. This study aims to fill this gap. Three anionic foaming surfactants were characterized and tested with the two commonly used screening methods at room temperature and oil-free conditions. The results were comprehensively analyzed to compare their foaming performance. The analysis is more comprehensive than previously reported and covers many foaming attributes (peak and residual foamability, foam longevity, and rate of decay). The three surfactants for possible foaming applications in sandstone reservoirs were selected, and their foamability and foam stability performances were experimentally determined by bulk foam stability tests and coreflood tests. All methods agreed on the ratings of the three surfactants for peak and residual foaming attributes as follows in the following order of effectiveness: MFOMAX, AOS, and ENORDET. However, they broadly disagreed on ratings for other characteristics including onset of foaming, the time required for peak foaming, foam longevity, and foam decay rate. In conclusion, the screening tests revealed that the simple and faster bulk foam stability test could be cautiously used to screen out the poor performers to narrow the range of acceptable surfactants. Also, the new and rigorous analysis technique presented in this paper offers more insight than conventional half-life test.
Two conventional approaches for foam screening are core/sandpack flooding and bulk foam stability tests. The former is more accurate, but requires expensive equipment and long test duration. For initial screening, the faster and cost-effective bulk foam stability tests are used to narrow down the selection to a few surfactants, which are then further tested using corefloods/sandpacks. The bulk foam stability tests have been historically used for surfactant selection at a fixed salinity and fixed surfactant concentration. The foam generated in bulk foam stability test was observed to be quite homogeneous, whereas foam generated through porous media is more heterogeneous; hence, a modification to the bulk foam test was made in that a small quantity of quartz river sand was placed at the bottom of the test tube for generating foam that simulates porous media. To evaluate the use of bulk foam and modified bulk foam stability tests for screening and optimizing salinity and surfactant concentrations, sandpack flooding tests were conducted at a range of salinities, and surfactant concentrations and results were compared. Bulk foam stability tests results were found to be compatible with sandpack results for surfactant concentration optimizations, but showed significant deviation for salinity optimization. The modified bulk foam stability tests, however, showed better agreement with sandpack results in both salinity and surfactant concentration tests.
Gas resources play a key role in nowadays energy supply and provide 24% of the diverse energy portfolio. Water encroachment is one of the main trapping mechanisms in gas reservoirs. It decreases recovery by reduction of reservoir life, limits productivity and efficiency of wells, and elevates safety risks in gas production. The lack of a comprehensive study about water production problems is the primary motivation for this study. Contrary to the serious concern over the standalone investigation of an actual water production case study, less concern is put to deal with the problem comprehensively through an investigation of all potential sources and mechanisms, required methods, and available techniques. This study presents the potential sources of the problem, methods to identify it, and approaches to address it. Firstly, possible sources are described. Secondly, the diagnostic techniques are expressed. Then, practical solutions used in actual cases to overcome problems are elaborated. The solutions include both well- and reservoir-oriented approaches. Finally, all proper strategies are summarized to tackle the water problems in gas fields. The current study comprehensively presents the available methods for water control problems in parallel with conceptual and qualitative comparison. The finding of this study can be very constructive for better understanding of water sources, available diagnostic tools, and solutions for controlling water production in gas reservoirs and, consequently, taking the best decision in real case studies before attempting many water shut-off approaches.
The gas injection is one of the most common methods to increase oil recovery. However, there are several drawbacks in the application of this method due to density and viscosity differences between displaced and displacing fluids. In order to tackle these drawbacks, gas can be utilized as different forms of foam which one of these methods is called Surfactant-Alternating-Gas (SAG). Although many studies have been conducted on foam flow through porous media, the behavior of foam still is moot to some extent. Since, the elaboration of SAG foam behavior in porous media is the aim of this study. However many parameters affect SAG foam behavior, the injection flow rate plays a significant role in foam behavior. In this study, we investigated the flow rate’s effect on SAG behavior. To achieve this target, several cores flooding, in the absence of oil, were conducted and results were interpreted. The experimental design for this work included core flooding apparatus, IOS as surfactant and nitrogen as injected gas. The experiments were interpreted in term of liquid recovery and pressure drop. The results show that the SAG efficiency highly depends on gas flow rate which high injection flow rate, low SAG foam efficiency.
The fractional flow equation is simplified by neglecting the effect of capillary pressure gradient. However, zero capillary pressure assumption may induce error in the fractional flow equation. The effect of different parameters on capillary pressure gradient in fractional flow is determined with numerical analysis based on the saturation distribution profile. The fractional flow equation is dependent on the relative permeability and relative permeability is a function of saturation. This project presents one-dimensional black oil simulation in core flooding using gas-water system to compare the saturation profile with capillary pressure and without capillary pressure. A factorial design was established for four (4) different parameters, i.e., porosity, permeability, length and injection rate, in three (3) levels (34=81). Therefore, eighty-one (81) simulations were conducted and the results were analyzed via Design of Experiments. This study found that porosity, permeability and injection rate has visible effect in the saturation profile due to the negligence of capillary pressure. Due to the limitation of the simulator, the end capillary effect was not captured in this study. Hence, the capillary pressure has no visible effect towards the core length.
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