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Enhanced Oil Recovery techniques are one of the top priorities of technology development in petroleum industries nowadays due to the increase in demand for oil and gas which cannot be equalized by the primary production or secondary production methods. The main function of EOR process is to displace oil to the production wells by the injection of d...
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... crude oil is classified as light crude oil since its API gravity is 35.7°. Table 1 shows the compositional analysis of the crude oil. Synthetic formation brine was used as the aqueous phase with the composition shown in table 2. The cores are then flooded with Sea water (50,000 ppm of NaCl) to bring the oil saturation to the residual saturation (Sor-1). ...
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Citations
... from the first section (10 mm from the CO2 exposed end) but, little or no recoveries of heavy hydrocarbons were observed from the remaining two sections of the rod. Emirates (Abdulkhalek, 2018). ...
... (2) Nitrogen flooding (5cc) followed by low salinity water flooding (60 cc), and (3) Carbon dioxide flooding (5 cc) followed by low salinity water flooding (60 cc) (Abdulkhalek, 2018). ...
... 42 Table 3.5: Summary of enhanced oil recovery results (Abdulkhalek, 2018). ...
The demand of petroleum energy in the world keeps on increasing on day-to-day basis. Due to the depletion of petroleum reserves in the world, enhancing crude oil recovery has been a major concern in the 21st century. Gaseous enhanced oil recovery techniques have been very successful in recovering the residual oil from the oil reserves due to their ability of penetrating and displacing significant amount of residual oil in low permeable reservoirs. This paper reviews some of the recent research papers on different GEOR methods. Based on the information obtained from the research papers, a comparison of different GEOR techniques was made in terms of their mode of application, the cost of operation, their oil recovery efficiencies as well as their suitable oil reservoir conditions. This paper also provides some basic knowledge and principles on the selection of a GEOR process together with their challenges and limitations.
... The crude oil samples were light grade. The average API gravity and density of the Bu Hassa light grade (BHLG) oil samples were measured using PVT cell under ambient conditions and recorded to be 35.7 • ± 0.1 and 0.855 × 10 − 3 gm/L ± 0.002, respectively (Lwisa and Abdulkhalek, 2021). The compositional analysis of the crude oil samples were carried out through Gas-Liquid Chromatography and the results are tabulated in Table 1 (Lwisa and Abdulkhalek, 2021). ...
... The average API gravity and density of the Bu Hassa light grade (BHLG) oil samples were measured using PVT cell under ambient conditions and recorded to be 35.7 • ± 0.1 and 0.855 × 10 − 3 gm/L ± 0.002, respectively (Lwisa and Abdulkhalek, 2021). The compositional analysis of the crude oil samples were carried out through Gas-Liquid Chromatography and the results are tabulated in Table 1 (Lwisa and Abdulkhalek, 2021). ...
Oil spills, which are often caused by crude oil transportation accidents, contaminate coastal waters and land and can harm aquatic life, seabirds, humans, and the entire ecosystem. Ocean currents and wind complicate oil spill cleanup and extend the oil spill area. This study proposes a new approach to control oil spills using solids recovered from the treatment of reject brine through a novel multistage desalination process. The aim is to produce applicable adsorbent for oil spill cleanup especially in the final cleaning stages. The multistage desalination process is based on the electrochemical treatment of high-salinity reject brine and Solvay and modified Solvay liquid effluents in a closed Plexiglas electrocoagulation cell. After the electrochemical treatment, the collected solids were dried and ground for utilization as adsorbents in oil spill cleanup. Results were promising for the adsorbent produced from the electrochemical treatment of the modified Solvay effluent. A maximum adsorption capacity of 2.8 g oil/g adsorbent was achieved, with an oil recovery of 98%. In addition, the regenerated solids after toluene extraction process were recycled and achieved an adsorption capacity of 2.1 g oil/g adsorbent in the second oil spill clean-up cycle. The structural and chemical characteristics of the adsorbents produced from the multistage desalination process were investigated using X-ray powder diffraction, Fourier transform infrared spectroscopy, and scanning electron microscopy. Results support the adoption of the collected solids as effective oil-adsorbent materials.
... With the continuous hierarchy division of reservoir and interwell infill in multilayer sandstone reservoir, the injection-production pressure system is constantly improved and strengthened. In the process of oil production, from primary oil recovery, secondary oil recovery to tertiary oil recovery, reservoir energy supplement has always been one of the most important methods to EOR [15][16][17][18]. Elastic energy recovery, dissolved gas driving, gas driving, steam huff and puff, and so on, the mechanism of EOR is essential to maintain or increase the formation energy. ...
The type-III oil formations in Daqing Oilfield are the representatives of medium-low permeability reservoirs in ultrahigh water cut oilfields of China, which is characterized by bad connectivity of pores and throats, dispersed residual oil distribution, and difficult to displace effectively. In order to produce the residual oil, we propose a new EOR (enhanced oil recovery) method which is hydraulic fracturing by an oil displacement agent at high pressure. In this paper, firstly, we have performed three sets of displacement experiments under different conditions to provide the basis for the analysis of changes in core pore structure and wettability. Next, overburden pressure porosity and permeability tests were used to analyze the effect of the injection of an oil displacement agent at high pressure on core physical properties. Correspondingly, the constant speed mercury injection tests were used to determine the radius distribution of pore throat and change of seepage resistance under different displacement conditions. Moreover, the scanning electron microscopy (SEM) tests of cores were carried out to observe and analyze changes in pore-throat size and connectivity, mineral particle accumulation, and cementation before and after hydraulic fracturing by an oil displacement agent at high pressure. Finally, core wettability tests were conducted to discuss and analyze the rule of core wettability change in hydraulic fracturing by an oil displacement agent at high pressure, and its mechanism of wettability changes. Research shows that increasing the formation energy is the most important mechanism of EOR by a fracturing-seepage-displacement method. Additionally, the type of an oil displacement agent has less effect. After an oil displacement agent at high pressure is injected to fracture the formation, it not only provides efficient flow channel and larger sweep volume for an oil displacement agent. Under the flushing action of high-pressure injection fluid, the original way of line or point contact between mineral particles gradually changes to free particles. Therefore, the pore throat size increases, some larger pores are formed, and the overall flow resistance decreases. After the injection of fluid at high pressure, the energy in formation has increased and the core wettability changes from oil-wet to weakly water-wet. This is not only because the residual oil on the pore surface is flushed by high pressure; in addition, the adsorption of an oil displacement agent on the rock surface reduces the liquid-solid interface energy and changes the wettability, thus improving the oil displacement efficiency.
1. Introduction
Nowadays, about 70% of Chinese oil production is still exploited from the old oilfields. For a period of time in the future, the old oilfields will still be the main Chinese oil supply [1–5]. Take Daqing Oilfield of China as an example, at present, water driving is still the main way of oil development. The general water cut is about 92.7%, but the recovery rate is only about 35%: thus, there is great potential for further EOR in this area [6–9]. Additionally, the remaining oil mainly exists in medium-low permeability reservoirs. While these reservoirs are always bad in physical properties and the distribution of remaining oil is relatively dispersed, it is difficult to inject the oil displacement agent and, definitely, the remaining oil is difficult to be produced [10, 11]. Therefore, there is an urgent need for a reasonable oil formation improvement method that can effectively produce the oil and release the dispersed remaining oil.
The development experience of large oilfields in the United States and Russia shows that oil production is a process of gradual improvement, which is mainly reflected in the increasingly reservoir hierarchy division and the increasing density of well pattern [12–14]. With the continuous hierarchy division of reservoir and interwell infill in multilayer sandstone reservoir, the injection-production pressure system is constantly improved and strengthened. In the process of oil production, from primary oil recovery, secondary oil recovery to tertiary oil recovery, reservoir energy supplement has always been one of the most important methods to EOR [15–18]. Elastic energy recovery, dissolved gas driving, gas driving, steam huff and puff, and so on, the mechanism of EOR is essential to maintain or increase the formation energy. After all, enough pressure is the fundamental driving force of crude oil development; enough pressure difference ensures the successful exploitation of crude oil sustainable development.
Hydraulic fracturing, as a direct and effective stimulation measure, has been widely used in oilfields all over the world. With the exploration, development, and utilization of shales and other unconventional reservoirs, hydraulic fracturing has become a necessary means to result in complex fracture systems instead of simple planar fractures and provide flow channel for oil and gas [19–21]. For a long time, the fracturing fluid with high viscosity and low filtration has been widely used in the fracturing operation domestically and overseas [22–24]. These fracturing fluids generally have the advantages of high viscosity and low fluid loss. The commonly used fracturing fluids are represented by guanidine or modified guanidine. Vegetable gum water-based fracturing fluid is one of the most commonly used fracturing fluids, which is used earlier. Its high viscosity and low fluid loss can satisfy the needs of fracturing and carrying sand [25–27]. In order to further improve the fracturing performance effect, various fracturing fluid systems have been developed successively, such as crosslinked polymer gel fracturing fluid system [28], foam fracturing fluid system [29], VES fracturing fluid system [30, 31], cellulose fracturing fluid system, and so on [32]. These developments have improved the temperature resistance, shear resistance, sand carrying capacity, and wall building performance of the fracturing fluid system.
Since the first hydraulic fracturing well was constructed in 1947, hydraulic fracturing has always been used to establish a high-speed flow channel to increase oil and gas production and injection [33, 34]. At the later stage of oilfield development, it is difficult to effectively use the dispersed remaining oil in medium-low permeability reservoirs. In view of the above problems, our research team proposed a new EOR method: hydraulic fracturing by an oil displacement agent with high pressure. In this method, the oil displacement agent with low initial viscosity is used as fracturing fluid, and the oil displacement agent is carried to the target reservoir by the way of hydraulic fracturing. The oil displacement agent is rapidly pushed to the enrichment position of remaining oil through fractures, so as to achieve the higher efficiency of oil displacement. The process of hydraulic fracturing is transformed into the process of fracturing-seepage-oil displacement along the direction of perpendicular to the fracture. In this way, the displacement agent can quickly enter the pores; thus, the contact time and distance between the oil displacement agent and the formation can be shortened effectively. So it can solve the problems of higher fracturing fluid loss and lower utilization efficiency of the oil displacement agent in the traditional injection process. As we all know, the oil recovery depends on effective swept volume and oil displacement efficiency. Only when the swept volume reaches a certain extent, the oil displacement efficiency can be improved; only by effectively improving the liquid absorption capacity of medium-low permeability layers or small-medium pores in the reservoir can the swept volume be expanded and the oil recovery be greatly enhanced [35–37]. This new EOR method of fracturing-seepage-oil displacement combines the advantages of increased formation pressure, expanded swept volume, and enhanced oil displacement efficiency.
In this paper, aiming at the hydraulic fracturing by an oil displacement agent with high pressure we proposed, a series of studies on micro displacement mechanism has been carried out. The natural core parameters, including permeability, porosity, pore throat structure, and wettability, were tested by overburden porosity and permeability instrument, constant speed mercury injection instrument, scanning electron microscope (SEM), contact angle instrument, and oil displacement device. We have designed a series of experiments to compare and analyze the effects on micropore structure of cores under different conditions, including oil displacement at conventional speed, oil displacement by water at high pressure, and oil displacement by oil agent displacement at high pressure. On this basis, we clarified the micro oil displacement mechanism of hydraulic fracturing by an oil displacement agent at high pressure.
2. Materials and Methods
2.1. Experimental Materials
In this EOR method, as the oil displacement agent was injected under the condition of high pressure and would fracture the reservoir, it could also be regarded as the fracturing fluid. The oil displacement agent was the surfactant (petroleum sulfonate), which was provided by the Daqing Oilfield Downhole Operation Branch Company. The fracturing fluid used in the comparison experiment was water. The water in the experiments was prepared in the on-site construction of the Downhole Operation Branch Company. The oil in the experiments was simulated oil, which was a mixture of degassed and dehydrated crude oil and light hydrocarbon oil in Daqing Oilfield. The viscosity of the simulated oil was 8.86 mPa·s at 45°C. The cores in the experiments were natural cores, which were taken from the type-III formations of No.1 oil production plant in Daqing Oilfield. The diameter of natural core was 2.5 cm, and the permeability was in the range of μm² to μm².
2.2. Instrument and Facilities
In this study, we carried out three sets of displacement experiments under different conditions to provide the basis for the analysis of changes in core pore structure and wettability at first. Based on them, overburden pressure porosity and permeability tests, core pore radius distribution test, microstructure change test, and wettability change test were performed. The main device used in the experiments included an overlaying pressure pore-permeability instrument, constant speed mercury injection instrument, scanning electron microscope (SEM), and contact angle tester. The microscopic pore structure parameters of the core were measured by a constant speed mercury injection instrument. A Fei Tecnai G2 F20 scanning electron microscope (SEM) from Gatan Company, USA, was used to test the micromorphology of natural cores. The equipment used in oil displacement experiments mainly includes an advection pump, pressure gauge, and oil displacement agent container. Except for the advection pump, the other facilities were placed in an oven with a constant temperature of 45°C. The displacement pressure was provided by the advection pump, and the fluid in the intermediate container was injected into the cores. In order to compare the effects of conventional displacement and fracturing-seepage-displacement methods at high pressure on the microscopic pore throat structure and wettability changes of cores, we had designed three sets of experiments, including the following: (a) oil displacement at conventional speed, the injection rate was 0.1 mL/min and the injection volume was 30 PV (pore volume); (b) hydraulic fracturing by water flooding at high pressure, the injection pressure was 20 MPa and the injection volume was 30 PV; (c) hydraulic fracturing by oil displacement agent flooding at high pressure, the injection pressure was 20 MPa and the injection volume was 30 PV. Combined with the SEM test, the influence of different displacement conditions on the microstructure changes of cores was analyzed through the core samples after displacement obtained in this experiment. The schematic diagram of the experimental set-up is shown in Figure 1.
... Experimental studies on CO2based EOR are also common. [30][31][32][33] Jin et al. 30 carried out experimental studies on core samples from the Bakken shale formation, and found that supercritical CO2 injection facilitates the recovery of up to 65% of hydrocarbons in place; they also reported that CO2 is trapped in the reservoir over a wide pressure range. Eide et al. 31 reported experimental results on oil recovery by CO2 injection into fractured core sample using nuclear magnetic resonance (NMR) and X-ray computed tomography; they reported oil recovery in excess of 90% of the original oil in place. ...
Although enhanced oil recovery (EOR) is often achieved by CO2 injection, the use of acid gases has also been attempted, for example in oil fields in west Canada. To design EOR technologies effectively, it would be beneficial to quantify the molecular mechanisms responsible for enhanced recovery under various conditions. We report here molecular dynamics simulation results that probe the potential of recovering n-butane confined from silica, muscovite and magnesium oxide nano-pores, all proxies for subsurface materials. The three model solid substrates allow us to identify different molecular mechanisms that control confined fluid behavior, and to identify the conditions at which different acid gas formulations are promising. The acid gases considered are CO2, H2S, as well as their mixtures. For comparison, in some cases we consider the presence of inert gases such as N2. In all cases, the nano-pores are dry. The recovery is quantified in terms of the amount of n-butane displaced from the pore surface as a function of amount of gases present in the pores. The results show that the gas performance depends on the chemistry of the confining substrate. While CO2 is more effective at displacing n-butane from the protonated silica pore surface, H2S is more effective in muscovite, and both gases show similar performance in MgO. Analysis of the interaction energies between the confined fluid molecules and the surface demonstrates that the performance depends on the gas interaction with the surface, which suggests experimental approaches that could be used to formulate the gas mixtures for EOR applications. The structure of the gas films at contact with the solid substrates is also quantified, as well as the self-diffusion coefficient of the fluid species in confinement. The results could contribute to designing strategies for achieving both improved hydrocarbon production and acid gas sequestration.
Foam Enhanced Oil Recovery (EOR) has been employed as an improved recovery method due to its best sweep efficiency and best mobility control over the other injection method such as gas flooding, water flooding and other EOR methods. Foam which has high viscosity illustrates great potential for displacing liquid. The relative immobility of foam in porous media seems to be able to suppress the formation of fingers during oil displacement leading a more stable displacement. However, there are still various parameters that may influence the efficiency of foam assisted oil displacement such as oil properties, permeability of reservoir rock, physical and chemical properties of foam, and other parameters. Also, the interaction and displacement patterns of foam inside the porous media are remained unknown. Thus, in this study, we investigated the three-dimensional (3D) characteristics of oil recovery with gases, water, surfactant, and foam injection in a porous media set-up. By using CT scanning machine, the fluid displacement patterns were captured and analyzed. Moreover, the effect of oil viscosity on foam displacement patterns is studied. The study provides a qualitative and quantitative experimental visualization of 3D displacement structure, oil recovery with gases, liquid and foam injection. As a result, the comparison of fluid displacement patterns between gases, water, surfactant and foam injection show that foam has the good ability in sweeping and forms stable displacement front. The combination of surfactant, liquid and gas, which makes up foam resulted in a synergistic effect in oil displacement. On the other hand, viscous fingering, gravity segregation, trapped oil phenomena are shown in gas flooding and liquid flooding experiments. Thus, foam which displaced stably across the permeable bed resulted in the highest oil recovery factor. The mechanism of foam flow in porous media was understood in this study. Foam, as a series of bubble, burst and become free moving liquid and gas particles when in contact with oil and porous media. Therefore, two displacement fronts could be found from the foam injection experiment, in which the front layer moving ahead in contacting with oil bank is the discontinuous gas/liquid layer and followed by stably foam bank at the back. Due to the stable displacement of foam bank, the effect of oil viscosity on foam displacement is suppressed and showed no distinction in terms of displacement patterns. The flow regimes are found to be the same despite different viscosity of displaced oil. There has been no linear correlation proved between the oil viscosity and oil recovery factor.
Even though the interest in CO2 foam flooding for enhanced oil recovery applications is increasing, having a successful operation in field scale is challenging. The efficiency of the conventionally surfactant stabilized foam is jeopardized under reservoir conditions.
In this study, we experimentally investigate the performance of a foam system consisting of a surfactant with the addition of CNC particles for operation at up to 2.7 MPa pressure and 90°C temperature. Experiments are conducted in static and dynamic conditions. The effect of addition of CNC nanoparticles to the surfactant solution in order to stabilize the foam structure is studied. In this paper, we demonstrate stabilization of foam through incorporating fully water wet nanoparticles, which generate a 3D network within the liquid film. These particles are not interfacially adsorbent. Investigation of these partition-favorable particle stabilized foams suggests that the non-adsorbed particles increase the stability of the foam via accumulation of CNC particles in a continuous phase between dispersed gas bubbles. The target of this study is CO2 flooding in conventional, hot conventional and viscous oil reservoirs.
