Feasibility of Gas Injection Efficiency for Low-Permeability Sandstone Reservoir in Western Siberia: Experiments and Numerical Simulation

Gas injection is one of the prospective methods in the development of unconventional oil reserves. Before implementation in the field, it is necessary to justify the effectiveness of using gas agents in specific object conditions. Experiments of oil displacement on physical models with subsequent numerical modeling can provide the information necessary to justify the feasibility of using gas injection in specific reservoir conditions. This work is devoted to a series of experiments determining the minimum miscibility pressure (MMP) on a slim tube model and the analysis of oil displacement dynamics for various gas compositions, as well as numerical modeling. Displacement experiments were carried out using a recombined oil sample from one of the fields in Western Siberia. The MMP was determined by the classical method of inflection point on the displacement efficiency versus injection pressure curve, which was 34.6 MPa for associated petroleum gas (APG) and 49.9 MPa for methane. The dysnamics of oil displacement for different gas compositions at the same injection pressure showed that APG and carbon dioxide (CO2) are the most effective in the conditions of the studied field. The influence of the gas composition on the gas breakthrough point was also shown. It is revealed that the change in the concentration of the displacing agent in the outgoing separation gas helps define in more detail the process of displacement and the processes implemented in this case for various displacing gas agents. Similarly, it is shown that the displacing efficiency of a gas agent in a miscibility injection mode is affected by the configuration of wells when it is necessary to achieve MMP in reservoir conditions. For the immiscible gas injection mode, no influence of the well configuration was observed.

Numerical Simulation via CFD Methods of Nitrogen Flooding in Carbonate Fractured-Vuggy Reservoirs

A reservoir-scale numerical conceptual model was established according to the actual geological characteristics of a carbonate fractured-vuggy reservoir. Considering the difference in density and viscosity of fluids under reservoir conditions, CFD (computational fluid dynamic) porous medium model was applied to simulate the process of nitrogen displacement in a fractured-vuggy reservoir after water flooding. The effects of gas injection rate, injection mode, and injector–producer location relation were studied. The results show that nitrogen flooding can yield additional oil recovery of 7–15% after water flooding. Low-speed nitrogen injection is beneficial in obtaining higher oil recovery. High speed injection can expand the sweep area, but gas channeling occurs more easily. In gas–water mixed injection mode, there is fluid disturbance in the reservoir. The gas channeling is faster in low injector–high producer mode, while the high injector–low producer mode is beneficial for increasing the gas sweep range. Nevertheless, the increment of recovery is closely related to well pattern. After nitrogen flooding, there are still a lot of remaining oil distributed in the trap area of gas cap and bottom water in the reservoir that water and gas injection can’t sweep. The establishment of the numerical conceptual model compensates for the deficiency of physical simulation research, stating that only limited parameters can be simulated during experiments, and provides theoretical bases for nitrogen flooding in fractured-vuggy reservoir.

Enhancement of refrigeration system performance by refrigerant capillary injection in evaporator

In this paper, the enhancement of refrigeration system performance by refrigerant capillary injection in evaporator was experimentally investigated. An experimental bench was developed in order to compare the performance of a refrigeration system operating in conventional throttling and capillary injection modes. The temperature distribution in the evaporator and the compressor electrical consumption were determined, showing that in the capillary injection mode, the refrigeration system was more stable, its time to reach the steady state was reduced by 62.5 % and its COP was enhanced by 9 %.

Effects of the Multiple Injection Strategy on Combustion and Emission Characteristics of a Two-Stroke Marine Engine

This paper presents research on the effects of the multiple injection strategies on the combustion and emission characteristics of a two-stroke heavy-duty marine engine at full load. The ANSYS FLUENT simulation software was used to conduct three-dimensional simulations of the combustion process and emission formations inside the engine cylinder in both single- and double-injection modes to analyze the in-cylinder pressure, temperature, and emission characteristics. The simulation results were then compared and showed good agreement with the measured values reported in the engine’s sea-trial technical reports. The simulation results showed reductions in the in-cylinder pressure and temperature peaks by 6.42% and 12.76%, while NO and soot emissions were reduced up to 24.16% and 68%, respectively, in the double-injection mode in comparison with the single-injection mode. However, the double-injection strategy increased the CO2 emission (7.58%) and ISFOC (23.55%) compared to the single-injection. These are negative effects of the double-injection strategy on the engine that the operators need to take into consideration. The results were in line with the literature reviews and would be good material for operators who want to reduce the engine exhaust gas emission in order to meet the stricter IMO emission regulations.

Non-recombination injection mode

A new type of injection regime is considered – non-recombination one, which can be realized in the forward direction of the current in structures of the p-n-n+ type under conditions of opposite directions of ambipolar diffusion and drift of non-equilibrium carriers. This is possible only if the accumulation at the n-n+ junction is stronger than the injection through the p-n junction, i.e., the concentration of carriers at the boundary of the n-base with the n-n+ junction is higher than their concentration at the boundary of the n-base with the p-n junction. In this mode, the dependences of the current on the voltage of the type J ~ V, and then J ~ V2 appear. Experimentally, such a behavior of the current-voltage characteristic is observed for the Al–Al2O3–CdTe structure.

Experimental Investigation on Enhanced-Oil-Recovery Mechanisms of Using Supercritical Carbon Dioxide as Prefracturing Energized Fluid in Tight Oil Reservoir

Summary Fracturing is the necessary means of tight oil development, and the most common fracturing fluid is slickwater. However, the Loess Plateau of the Ordos Basin in China is seriously short of water resources. Therefore, the tight oil development in this area by hydraulic fracturing is extremely costly and environmentally unfriendly. In this paper, a new method using supercritical carbon dioxide (CO2) (ScCO2) as the prefracturing energized fluid is applied in hydraulic fracturing. This method can give full play to the dual advantages of ScCO2 characteristics and mixed-water fracturing technology while saving water resources at the same time. On the other hand, this method can reduce reservoir damage, change rock microstructure, and significantly increase oil production, which is a development method with broad application potential. In this work, the main mechanism, the system-energy enhancement, and flowback efficiency of ScCO2 as the prefracturing energized fluid were investigated. First, the microscopic mechanism of ScCO2 was studied, and the effects of ScCO2 on pores and rock minerals were analyzed by nuclear-magnetic-resonance (NMR) test, X-ray-diffraction (XRD) analysis, and scanning-electron-microscope (SEM) experiments. Second, the high-pressurechamber-reaction experiment was conducted to study the interaction mechanism between ScCO2 and live oil under formation conditions, and quantitively describe the change of high-pressure physical properties of live oil after ScCO2 injection. Then, the numerical-simulation method was applied to analyze the distribution and existence state of ScCO2, as well as the changes of live-oil density, viscosity, and composition in different stages during the full-cycle fracturing process. Finally, four injection modes of ScCO2-injection core-laboratory experiments were designed to compare the performance of ScCO2 and slickwater in terms of energy enhancement and flowback efficiency, then optimize the optimal CO2-injection mode and the optimal injection amount of CO2slug. The results show that ScCO2 can dissolve calcite and clay minerals (illite and chlorite) to generate pores with sizes in the range of 0.1 to 10 µm, which is the main reason for the porosity and permeability increases. Besides, the generated secondary clay minerals and dispersion of previously cemented rock particles will block the pores. ScCO2 injection increases the saturation pressure, expansion coefficient, volume coefficient, density, and compressibility of crude oil, which are the main mechanisms of energy increase and oil-production enhancement. After analyzing the four different injection-mode tests, the optimal one is to first inject CO2 and then inject slickwater. The CO2 slug has the optimal value, which is 0.5 pore volume (PV) in this paper. In this paper, the main mechanisms of using ScCO2 as the prefracturing energized fluid are illuminated. Experimental studies have proved the pressure increase, production enhancement, and flowback potential of CO2 prefracturing. The application of this method is of great significance to the protection of water resources and the improvement of the fracturing effect.

Offshore Heavy Oil Polymerflooding Pilot Reveals Alternative Paths

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30277, “Twelve-Year Field Applications of Offshore Heavy Oil Polymerflooding From Continuous Injection to Alternating Injection of Polymer and Water,” by Guangming Pan, Lei Zhang, and Jianting Huang, CNOOC, et al., prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2-6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Polymerflooding has been considered a suitable method for reservoirs with viscosities up to 150 mPa·s. The authors of the complete paper verify that alternating injection of polymer and water in the Bohai Bay of China proved effective and economical for heavy oil fields, even offshore. This polymerflooding pilot of initially continuous, and then alternating, injection can provide a useful technical reference for similar reservoirs. Introduction Heavy oil reserves are abundant in the Bohai oil field of China. The development of the field has proved that the field with lower viscosity (less than 350 mPa·s) can be developed effectively by water-flooding, while the unconventional heavy oil reservoir with high viscosity has not formed a mature development mode. To better use interwell reserves, a pilot polymerflooding test has been conducted in the NN field since 2008. The cumulative production of nine wells in the surrounding area reached 10.80×104 m3, which confirmed that polymer fluid injection had a good displacement effect on unconventional high-viscosity crude oil. However, with the extension of continuous injection time, the pilot test area faced various problems. In order to explore the applicability of polymerflooding technology used in offshore unconventional heavy oil fields, the polymer-injection mode was studied on the basis of laboratory experimental data and field practice, and the polymer/water alternating injection mode was analyzed. Experimental Continuous Polymerflooding. Experimental Equipment and Materials. The experimental device is composed of a driving system, an experimental model, a pressure-measurement system, a produced-liquid-collection system, and a temperature-control system. According to the distribution of reservoir physical properties in the NN field, a parallel double-tube displacement experiment with a permeability ratio of 5 was designed. The experimental cores are artificial, with a tube length of 30 cm and an inner diameter of 2.54 cm. The low-permeability tube has 1624×10-3 µm2 permeability, and the high-permeability tube has 8488×10-3 µm2 permeability. The experimental temperature is 55°C, which is consistent with the formation temperature of the NN field. The polymer is partially hydrolyzed polyacrylamide. Experimental Procedure. The experimental process includes vacuum pumping, saturating formation water, obtaining core pore volume, saturating simulated oil, calculating oil saturation water drive to a specified water cut, continuously injecting polymer solution, and measuring data. The experimental injection rate is 0.2 mL/min, and the multiple of injected pore volumes (PV) is 0.6 PV. The NN field has weak edge water, and the water cut of the well group was 60 to 90% when polymerflooding was performed. Therefore, the design scheme mainly includes waterflooding and polymerflooding stages. The polymer- injection concentration was 3000 mg/L, and the injection mode is continuous, consistent with the field test.

Investigation on the Controlling Factors of Pressure Wave Propagation Behavior Induced by Pulsating Hydraulic Fracturing

Summary Pulsating hydraulic fracturing (PHF) is a promising fracturing technology for unconventional reservoirs because it could improve the hydraulic fracturing efficiency through inducing the fatigue failure of reservoir rocks. Understanding of the pressure wave propagation behavior in wellbores and fractures plays an important role in PHF optimization. In this paper, a transient flow model (TFM) was used to describe the physical process of pressure wave propagation induced by PHF, and this model was solved by the method of characteristics (MOC). Combination of the TFM and MOC was validated with experimental data. The impacts of controlling factors on the pressure wave propagation behavior were fully discussed, and these factors include the frequency of input loading, an injection mode, an injection position, and friction. More than 10,000 sets of pressure wave propagation behaviors in different scenarios were simulated, and their differences were illustrated. In addition, the generation mechanisms of different pressure wave propagation behaviors were explained by the Fourier transform theory and the vibration theory. The important finding is that there is resonance phenomenon in the propagation of the pressure wave, and the resonance frequencies are almost equal to the natural frequencies of a fluid column. As a consequence of resonance phenomenon, the amplitudes of bottomhole pressure (BHP) and fracture tip pressure will increase sharply when the input loading frequency is close to the resonance frequency and less than 5 Hz; otherwise, the resonance phenomenon will disappear. Furthermore, an injection mode can alter the resonance frequency and the amplitude and frequency of the induced pressure wave. In addition, a friction effect can significantly decrease both the resonance frequency and the resonance amplitude. These findings indicate that the optimized input loading frequency should be close to the natural frequency of a fracturing fluid in a wellbore to enhance its BHP.