Alternative Water Injection Research Articles

Evaluating the efficacy of water alternating gas injection technique in the upper jurassic hydrocarbon reservoirs, considering saturation pressure

A tertiary method of enhanced oil recovery (EOR) based on the watergas alternating injection process (WG) is examined in this article based on the ratio between saturation pressure and reservoir pressure. A hydrodynamic simulation of the WAG process was carried out using TEMPEST MORE software (version 7,1). Many hydrocarbon fields worldwide are currently experiencing declining production rates. However, by utilizing advanced technologies like alternate injection of water and associated petroleum gas, the final oil recovery factor (RF) can be significantly increased. To ensure successful water injection experiments in real fields, it is crucial to consider the ratio of saturation and reservoir pressures during injection. Any negligence in this regard can lead to failure of the experiments aimed at enhancing oil recovery through WAG application. The research examines two variations of reservoir system models with certainty. In the initial model, the saturation pressure is lower than the reservoir pressure, signifying an under-saturated state of the reservoir system containing dissolved gas. Consequently, when accompanying petroleum gas is introduced, it mixes with oil at precise thermobaric conditions. According to the second model, the reservoir is saturated with gas at a saturation pressure equivalent to the formation pressure. A thorough assessment indicates that the success of water alternating gas injection (WAG) is heavily influenced by the initial state of the reservoir. In situations where the reservoir is already saturated with gas, implementing water-gas stimulation may be ineffective as gas breakthroughs may occur rapidly. However, implementing WAG in saturated reservoirs can lead to a 1 – 8% rise in overall oil production, observable within 3 – 4 years, depending on the timing after waterflooding. Simultaneously, in the case of reservoirs with a low saturation pressure, which exhibits an undersaturated reservoir system, the implementation of water alternating gas injection can be seen as a viable approach for enhancing oil recovery. WAG is a proven method that confidently increases oil recovery up to 10% in undersaturated reservoirs compared to conventional waterflooding.

EVALUATION OF EFFICIENCY OF OIL DISPLACEMENT BY WATER AND GAS AT VARIOUS MODES

The purpose of the work is to analyze in detail the efficiency of oil displacement by various agents, such as water and gas, at different modes. During the study, various methods and technologies aimed at increasing oil recovery were considered, and the effect of various parameters on the efficiency of the process was studied.Particular attention was paid to the method of water-gas impact (HBV) using pump-ejector systems (PES), which provides a triple impact on oil formations by simultaneous or alternate injection of water and gas.Theoretical and experimental methods were used to conduct the study. The beginning of the work was the study and analysis of scientific sources on the issue of assessing the effectiveness of oil displacement. Further, laboratory tests were carried out to assess the effectiveness of oil displacement by various agents. Experimental studies were carried out on a two-phase and three-phase filtration unit. The main parameter measured was the coefficient of oil displacement by water and separation gas. The effectiveness of the impact of various modes of water and gas exposure was studied: alternating (cyclic) injection of water and gas with different cyclicity, simultaneous injection of water and gas, as well as injection of a fine water and gas mixture.Based on the results of the work, it was concluded that the degree of influence of wetting processes on the final displacement result is a critical factor. The following main points can be distinguished:- final value of oil displacement coefficient depends on selection of displacement agent;- in case of water and gas impact, the sequence of water and gas injection is of great importance;- the efficiency of oil displacement is highly dependent on the absolute permeability of the reservoir, as well as on the injection mode (sequential, simultaneous, cyclic).The results of the experiments can be useful for predicting the development of oil fields and choosing optimal methods for increasing oil recovery.The uniqueness of this article lies in the study of the possibilities of using multithreaded ejectors to increase the efficiency of hydrocarbon production.

Comprehensive integral simulation of first 3 weeks of severe accident at Fukushima Daiichi Unit 1. Part II – Simulation of the in-vessel and ex-vessel phases

This paper is the second part of the summary presenting the results of IBRAE work over last 12 years on severe accident investigation at Unit 1 of Fukushima Daiichi with the SOCRAT code. The paper supplements the part I that was published previously, and is dedicated to the description of one-through integral simulation results of the 3 weeks of accident unfolding starting from the tsunami arrival. The integral simulation encompasses the different processes at in-vessel and ex-vessel phases of the accident including the processes in reactor building. The important issues discussed are the hypothesis on the induced leak from a steam line, the operation of isolation condenser, the possible early combustion of hydrogen in the reactor building room that houses the drywell head, as well as the time, conditions and regime of hydrogen combustion in the reactor hall, the flowrate of alternative water injection, and the depth of concrete ablation. The main criterion for checking the adequacy of assumptions and the simulation results is the agreement with factual information available including the measurement data and the results of inverse calculations of the source term. The shortcomings of current simulation with the SOCRAT code are briefly considered as a perspective for improving the realism of results in the next studies.

MAAP code analysis for the in-vessel phase of Fukushima-Daiichi Nuclear Power Station Unit 1 and comparison of the results among Units 1 to 3

The accident progression of the in-vessel phase of Fukushima Daiichi Nuclear Power Station Unit 1 was analyzed using the MAAP code. Although there is a large uncertainty in the initial stage of accident progression behavior in Unit 1 with little measurement data, it is presumed to have similarities to that of Unit 3. As a result, in Unit 1, since there was almost no alternative water injection during the in-vessel phase, cooling of the debris transferred to the lower plenum was small. It was likely that a large molten pool of metals had formed, and that the steam supply to the high-temperature core materials was suppressed and metal oxidation was relatively small. The analysis results for Unit 1 were compared with those for Units 2 and 3, and differences between units such as the thermal conditions of the debris that relocated to the pedestal and the degree of metal oxidation were shown.

Investigation of the influence of water-gas exposure modes on the efficiency of oil displacement

The purpose of the work is to analyze the efficiency of oil displacement by various agents, such as water and gas, in different modes. The methods and technologies used to increase oil recovery are considered, as well as the influence of various parameters on the efficiency of the process.The authors describe in more detail the method of water-gas exposure (VGV) using pumping-ejector systems (PES) to provide a triple effect on oil reservoirs by simultaneous or alternate injection of water and gas. Theoretical and experimental methods were used to conduct the study. The study and analysis of scientific sources on the issue of evaluating the effectiveness of oil displacement became the first stage of the study. Then laboratory tests were carried out to assess the effectiveness of oil displacement by various agents. Based on the results of the work done, it was concluded that the degree of influence of wetting processes on the final result of displacement is an extremely important factor. The uniqueness of this article lies in the study of the possibilities of using multithreaded ejectors to increase the efficiency of extraction of hydrocarbones.

The Effectiveness of the Introduction of the Water-Alternated-Gas Injection on the example of a Carbonate Field in Kazakhstan

Background: Water-Alternated-Gas Injection (hereinafter referred to as WAG) is considered to be a suitable analogue of gas injection and waterflooding, which increase the efficiency of displacement. With continuous gas injection, the displacement front is unstable due to the low viscosity of the gas, which leads to the formation of gas tongues due to a significant difference in the mobility of gas and oil. Alternate injection of water and gas is considered a suitable option in eliminating this problem and in stabilizing the displacement front.
 Aim: The purpose of this work was to generalize the main factors affecting the efficiency of the process, based on the world experience in applying the WAG technology. The effectiveness of this technology application in a carbonate field was also considered.
 Materials and methods: This article analyzes the efficiency of oil displacement using the WAG method in a carbonate field in Kazakhstan. In order to study the proposed oil production technology, the alternate injection of water and gas into the reservoir was simulated on the ECLIPSE 100 simulator. First of all, the process of optimizing the parameters was carried out based on two injection wells. As a result, it was found that for the studied field, the duration of water and gas cycles of 3 months and the sequence of "gas water" are the optimal conditions for observing the greatest effect from WAG. Further, based on the selected parameters, WAG was scaled to the entire field, for the implementation of which several options were developed with 3, 5, 6 and 12 injection wells.
 Results: As a result of the research, the optimal oil displacement option was selected, which involves 5 injection wells with high injectivity and a large volume of injected gas.
 Conclusion: Due to the hydrophilicity of the reservoir, the effect of alternating WAG turned out to be not as significant as it could be expected, due to the effect of hysteresis of relative phase permeabilities, which can be a topic for future research.

Storage Ratio of CO2 Miscible Flooding in Chang 8 Reservoir of H Block in Ordos Basin Under Different Injection Methods

Carbon dioxide is a typical kind of greenhouse gases, and the oil and gas field recovery ratio could be significantly improved by injecting it into the formation. The main goal is to increase the recovery ratio in the early stage of studying gas injection miscible flooding. With the advancement of the “carbon neutral” strategy in China, the application of CO2 miscible flooding technology, which aims to enhance the oil recovery ratio in Chinese oilfields, has been further expanded. The development concept needs to change from simply improving the recovery ratio to improving both the recovery ratio and the CO2 storage ratio. In the current CO2 flooding research, people mainly focus on the improvement of the recovery factor, and less attention is paid to the underground storage of CO2. In order to further study the relationship between the displacement efficiency of CO2 and the storage situation, this paper innovatively combines the storage ratio and storage amount of CO2 with the recovery factor. A number of parameters under different injection methods in the study area were calculated, providing a new research angle for the study of CO2 displacement. Take Chang 8 reservoir in Block H of Ordos Basin as an example. Firstly, the minimum miscibility pressure (MMP) of CO2 at formation temperature was measured by the slim tube experiment according to the reservoir pressure status to judge the CO2 flooding status in the study area. Then, the numerical simulation model of the study area was established, and the historical fitting was completed according to the existing CO2 flooding test wells. The reservoir numerical simulation is used to study the recovery ratio and CO2 storage ratio under different CO2 miscible flooding, including different injection rates, injection sequences, and bottom hole pressures. The results show that the MMP of CO2 in the study area is between 12.65 and 14.80 MPa, which means the CO2 flooding state in this area is miscible flooding with high oil displacement efficiency. The CO2 storage ratio at 5–40 t/d CO2 injection rate is between 54.02% and 64.38% after 20 years, and the CO2 storage ratio is larger when the gas injection rate is 10 t/d. In combination with CO2 storage capacity and the oil recovery factor, it is recommended that the gas injection rate of a single well in the study area is 20–30 t/d. The CO2 storage ratio after 20 years under different gas injection sequences is 57.69%–61.27%. It is suggested that the study area should be injected with water and gas alternately after 2 years of gas injection. When continuous gas injection is used, the CO2 storage ratio under different production well bottom hole pressures is between 54.95% and 59.82%. It is recommended that the bottom hole flow pressure in the study area be maintained at between 9 and 10 MPa. The results show that the main factor that affects the annual CO2 storage ratio in the study area is the CO2 injection rate. Gas injection rate, injection sequence, and bottom hole pressure of production wells will all have an impact on the overall storage ratio. And alternate water and gas injection is quite significant. From the perspective of storage ratio, the optimal CO2 miscible flooding injection method has been optimized for the study area, which provides a reference for the implementation of CO2 underground storage technology in mines.

Optimization of Water-Alternating-CO2 Injection Field Operations Using a Machine-Learning-Assisted Workflow

Summary This paper will present a robust workflow to address multiobjective optimization (MOO) of carbon dioxide (CO2)-enhanced oil recovery (EOR)-sequestration projects with a large number of operational control parameters. Farnsworth unit (FWU) field, a mature oil reservoir undergoing CO2 alternating water injection (CO2-WAG) EOR, will be used as a field case to validate the proposed optimization protocol. The expected outcome of this work would be a repository of Pareto-optimal solutions of multiple objective functions, including oil recovery, carbon storage volume, and project economics. FWU’s numerical model is used to demonstrate the proposed optimization workflow. Because using MOO requires computationally intensive procedures, machine-learning-based proxies are introduced to substitute for the high-fidelity model, thus reducing the total computation overhead. The vector machine regression combined with the Gaussian kernel (Gaussian-SVR) is used to construct proxies. An iterative self-adjusting process prepares the training knowledge base to develop robust proxies and minimizes computational time. The proxies’ hyperparameters will be optimally designed using Bayesian optimization to achieve better generalization performance. Trained proxies will be coupled with multiobjective particle swarm Optimization (MOPSO) protocol to construct the Pareto-front solution repository. The outcomes of this workflow will be a repository containing Pareto-optimal solutions of multiple objectives considered in the CO2-WAG project. The proposed optimization workflow will be compared with another established methodology using a multilayer neural network (MLNN) to validate its feasibility in handling MOO with a large number of parameters to control. Optimization parameters used include operational variables that might be used to control the CO2-WAG process, such as the duration of the water/gas injection period, producer bottomhole pressure (BHP) control, and water injection rate of each well included in the numerical model. It is proved that the workflow coupling Gaussian-SVR proxies and the iterative self-adjusting protocol is more computationally efficient. The MOO process is made more rapid by squeezing the size of the required training knowledge base while maintaining the high accuracy of the optimized results. The outcomes of the optimization study show promising results in successfully establishing the solution repository considering multiple objective functions. Results are also verified by validating the Pareto fronts with simulation results using obtained optimized control parameters. The outcome from this work could provide field operators an opportunity to design a CO2-WAG project using as many inputs as possible from the reservoir models. The proposed work introduces a novel concept that couples Gaussian-SVR proxies with a self-adjusting protocol to increase the computational efficiency of the proposed workflow and to guarantee the high accuracy of the obtained optimized results. More importantly, the workflow can optimize a large number of control parameters used in a complex CO2-WAG process, which greatly extends its utility in solving large-scale MOO problems in various projects with similar desired outcomes.

Using cyclic alternating water injection to enhance oil recovery for carbonate reservoirs developed by linear horizontal well pattern

In view of high water cut and low oil recovery caused by the unidirectional flow in linear pattern of horizontal wells for the carbonate reservoirs in the Middle East, this paper provides a novel approach to improve oil recovery by converting linear water injection to cyclic alternating water injection patterns including cyclic alternating water injection with apparent inverted seven-spot pattern or apparent five-spot pattern and cyclic differential alternating water injection. The main advantage of using this strategy is that the swept efficiency is improved by changing injection-production streamlines and displacement directions, which means displacement from two different direction for the same region during a complete cycle. This technology is effective in increasing the swept efficiency and tapping the remaining oil, thus resulting in higher oil recovery. Field application with three new patterns in a carbonate reservoir in the Middle East is successful. By optimizing injection and production parameters based on the cyclic alternating well pattern, the test well group had a maximum increase of daily oil production per well of 23.84 m 3 and maximum water cut drop of 18%. By further optimizing the distance (keep a long distance) between the heels of injection and production wells, the waterflooding performance could be better with water cut decreasing and oil production increasing.

Technology Focus: Oilfield Chemistry (September 2021)

As production chemists, we are all aware of the overall concepts of improved oil recovery (IOR) and enhanced oil recovery (EOR). Perhaps, though, fewer of us are aware of the different idiosyncrasies that exist within (and even between) these two broad categories of recovery and then how chemistry and chemicals can have an effect upon these processes. I would like to propose that the lines once were quite distinct between IOR and EOR: IOR was a standard waterflood operation, and EOR (from a chemist’s perspective) was the addition of chemistry to that waterflood (typically polymer or surfactant). Nowadays, the science has evolved massively to create many sub-genres of IOR and EOR. A waterflood is rarely just a waterflood anymore. We can alternate water and gas injection. We can add chemical conformance aids to direct better the flow of water. We can change the salinity of the water to promote better wettability for higher recovery factors. The list goes on. One just has to search out the number of EOR papers vs. (pretty much) every other discipline of production chemistry to see the commitment this industry still has to the research of this discipline. In recent years, the focus has tended to move away from deep-reservoir EOR to focus on near-wellbore stimulation. Interestingly, the mechanistic considerations that we make as production chemists are nearly identical in all cases, and significant synergies exist between these subdisciplines. Therefore, from the recent research published by SPE, two focused topics of IOR/EOR have arisen: the use of nanoparticles and the use of water-shutoff technologies. Nanoparticle use is gaining significant traction in the oil and gas industry, and field applications are now being reported. The area of IOR/EOR is no exception. Water shutoff is not a new technology area. However, are these established, production-sustaining IOR techniques seeing a resurgence caused by the headwinds our industry has faced during the COVID-19 pandemic? Recommended additional reading at OnePetro: www.onepetro.org. OTC 30123 - Thermal and Rheological Investigations on N,N’-Methylenebis Acrylamide Cross-Linked Polyacrylamide Nanocomposite Hydrogels for Water-Shutoff Applications by Mohan Raj Keishnan, Alfiasal University, et al. IPTC 20210 - Chemical and Mechanical Water Shutoff in Horizontal Passive ICD Wells: Experience and Lessons Learned in Giant Darcy Reservoir by Mohamed Abdel-Basset, Schlumberger, et al. SPE 203831 - Efficient Preparation of Nanostarch Particles and Mechanism of Enhanced Oil Recovery in Low-Permeability Oil Reservoirs by Lei Zhang, China University of Geosciences, et al.

Experimental Study on Injection and Plugging Effect of Core-Shell Polymer Microspheres: Take Bohai Oil Reservoir as an Example.

To meet the technical requirements of deep fluid diversion in Bohai oilfield, the swelling property, plugging effect, transport characteristics of polymer microspheres, and fluid diversion effect in heterogeneous cores are studied in this paper. There are two kinds of polymer microspheres including core–shell microspheres and traditional microspheres. The instruments used in this study include a biomicroscope, a metallurgical microscope, a scanning electron microscope, and core displacement experimental devices. The results of microscopes indicated that the core–shell microspheres were successfully synthesized, and the microspheres had good hydration expansion effect. The expanded microspheres could attract each other through the electrostatic force of anions and cations to achieve the purpose of coalescence. Compared with traditional microspheres (initial particle size is 3.8 μm), the initial particle size of the synthesized core–shell microspheres is close to 3.3 μm, but the particle size distribution is more concentrated, so the injection performance is close to that of traditional microspheres (initial particle size is 3.8 μm). After 8 days of hydration expansion, although the expansion multiple is small, it can coalesce and enhance the plugging effect, which can adapt to a wider range of permeability, ranging from 200 × 10–3 to 3000 × 10–3 μm2 (200 × 10–3–1500 × 10–3 μm2 for traditional microspheres). Under the same conditions (heterogeneous core), compared with the traditional microspheres, the core–shell microspheres have the characteristics of coalescence. Therefore, its fluid diversion effect is better, and the oil recovery is increased by 5.5%. Nevertheless, there is the “end effect” during the injection process, which weakens the steering effect of deep liquid flow. The results show that the “end effect” can be effectively reduced by alternate injection of microspheres and water. Meanwhile, the effect of deep fluid diversion is improved, and the increase of oil recovery is increased by 2.06%.

Production optimization for alternated separate-layer water injection in complex fault reservoirs

Complex reservoirs possess some principal characteristics, such as strong geological heterogeneity, faults and multi-layers, etc. They can exert significant effects on the flow performance of water flooding vertically and horizontally. For most large-scale and well-connected reservoirs, water injection wells generally adopt manual adjustment method or intelligent well technology to control the water injection volume of a single well. However, these technologies are associated with high costs, and it is not a trivial task to obtain an optimal injection-production control for some complex reservoirs with small blocks or strong heterogeneity. More importantly, most complex fault block reservoirs have experienced multiple rounds of well pattern infilling adjustment in the development process, with large well pattern density, as well as because of complex structure, fault development and single injection production form of fault block reservoir. In view of the unbalanced vertical production of fault block reservoirs in high water cut stage, the alternative injection production mode is proposed to minimize the interlayer interference and achieve stable production under unstable injection production. However, the key parameters of the alternative injection production method are not clear and need to be optimized. Facing this situation, a new method for the injection-production optimization is proposed in this paper. This technology use underground regulator which can alternately open and close the different layers. Additionally, the heterogeneity of permeability is considered and a uniform displacement of water in each flooding unit is realized by adjusting the regulators of injectors and producers. By using this method, a series of measurements such as on-off time and injection volume can be chosen as decision variables. Hence, the commercial simulator and the optimization theory algorithm are used to optimize and adjust the alternative stratified water injection technology. Additionally, this method can be combined with field practice, save the cost of measurement and adjustment, and be easy to operate. This method can be combined with field practice, save the cost of measurement and adjustment, and be easy to operate. Detailed parameter optimization and results are presented with an example to prove the efficacy of the proposed methodology. The results show that the method proposed in this study can be successfully applied to optimization of well control and improve the reservoir development significantly.

Dissolution evaluation of coquina part 2: Alternating carbonated brine and equilibrated brine injection using computed tomography and PHREEQC

Geochemical modeling of CO2-water-rock chemical interactions plays a crucial role in enhanced oil recovery (EOR) processes and CO2 storage. This work develops a geochemical model and an injection sequence that alternates carbonated brine (CB) and equilibrated brine (EB). The model was fitted using the PHREEQC geochemical simulator and two sets of experimental data: (1) calcium and magnesium concentration from the effluents and (2) the amount of calcite dissolved from computerized tomography (CT) measurements. The model incorporates the overall assessment of the calcite kinetics theory and surface complexation. Chemical interactions on the mineral surface promote mineral dissolution and precipitation, which can lead to changes of permeability, porosity, and integrity of reservoir. To understand and simulate the chemical interaction between rock and the injection fluid, this work tested different flow rates (0.025, 0.075, 0.1, and 2 ml/min at 13.789 MPa and 20 °C) alternating the injection sequence of CB and EB. Permeability and porosity were evaluated using pressure measurements and CT, respectively. The Péclet (Pe) and Damköhler (Da) numbers were determined for each flow rate and the dissolution regime was characterized. We developed a geochemical model using the PHREEQC taking into account the theory of calcite kinetics and complexation surface to predict the behavior of mineral dissolution during reactive transport using CT (computed tomography) and effluent analysis. The novelty of alternating the injection sequence of CB and EB provided the chemical interaction between the coquina and the fluids, promoting dissolution of minerals, and thus altering permeability and porosity. Calculating Da and the reaction rate along the porous medium facilitated the evaluation and quantification of the different patterns of calcite dissolution, which were due to the flow rate variation and the alternate injection of water. Analysis showed that low flow rates promote greater dissolution at the beginning of the sample, high flow rates promote dissolution throughout the sample, and the sample heterogeneity also influences dissolution. Finally, we used surface complexation to correctly represent the effects of interactions between CB/EB and the coquina, as these interactions affect the quantity of magnesium production.

Changes in formation pressure and technological efficiency of unsteady flooding in double permeability reservoirs having different productivity rates

Unsteady waterflooding went through several stages. Within the pilot works in April 2009, cyclical water injection was started in Block 7 (central section). In addition, alternate water injection into the horizons of the Jurassic and Cretaceous sediments of Block 10 began. For this purpose, injection wells equipped with devices for simultaneous separate water pumping were used. The significant effect of non-stationary waterflooding in the experimental sections allowed for the application of the technology in other blocks. The technology implementation scheme was applied for injection wells of Blocks 6 and 10. Since July 2010, cyclic injection has been used for many wells. Periods of non-stationary operation of injection wells were determined experimentally. The reservoirs with heterogenous permeability containing highly permeable and low-permeable layers are the most optimal ones. The heterogenous structure of the reservoir provides a large contact area between layers with different permeability levels which allows for non-stationary effects due to the occurrence of overflows between the layers. It can reduce the water content of the products and increase oil production.

Water and gas mixture characteristics calculation and its possible injection variants

The aim of this article is the practical application of calculation methodology of water and gas volume injection into the reservoir and optimal parameters of water and gas mixture in Samodurovskoe field in Russia. Calculations were performed using two technologies: water alternating gas (WAG) and simultaneous water and gas injection (SWAG). For each case the optimum volume of water and gas mixture and its components which are injected into the reservoir was calculated. The variant of alternative water and gas injection cannot be applied in oilfield because of existing restriction to maximum flowrate of associated gas in standard conditions. In Samodurovskoe field can be applied water-alternated-gas (WAG) technology. Proper array of gas and water ration phases in reservoir condition with account of associated gas usage was calculated. Optimization of water-gas mixture volume ratio components showed that the biggest effectiveness of oil recovery cannot be reached resulting from abovementioned restriction. This calculation methodology can be used in job execution, it is simple and practical.

Sensitivity analysis of in-vessel accident progression behavior in Fukushima Daiichi Nuclear Power Plant Unit 3

The Great East Japan earthquake and the subsequent tsunami which occurred on March 11th 2011 put the operating Units 1–3 at Fukushima Daiichi Nuclear Power Plant (NPP) in severe accident conditions resulting from loss of offsite power and AC power. It is believed that the Station Blackout (SBO) and loss of heat sink led to core meltdown in all Units 1–3. Despite past research efforts on the severe accident progression in Fukushima NPP Units 1–3, there are still knowledge gaps and uncertainties existing in understanding of the severe accident scenarios and consequences.Hence, this study aims at identifying the modeling uncertainties and addressing the sensitivity parameters in Fukushima NPP Unit 3. A more detailed Control Volume (CV) division model of the reactor core region has been developed to better simulate the thermal-hydraulic behavior of liquid water and steam, which is considered to be crucial in simulating the core uncovery and degradation process. The boundary conditions such as the water injection rates by the Reactor Core Isolation Cooling (RCIC) system, the High Pressure Core Injection (HPCI) system and Alternative Water Injection (AWI) to the reactor core were determined based on the available reactor water level and pressure measurement data. The current study suggested that the local vapor heatup behavior could influence the core melting and relocation behavior, which can lead to different core degradation scenarios. With the current modeling assumptions in MELCOR, the best estimate conditions for RPV pressure history of Unit 3 suggested that 6 SRVs could have remained open when the major core slumping took place at ca. 45:20 h (ca. 12:00, March 13) with 50 to 80 tons of water inventory in the lower plenum. The current analysis also suggested that the efficiency of the AWI to the reactor core could have been only 15% as of reported by TEPCO with the current modeling conditions if debris dryout was assumed to have occurred at around ca. 54.0 h (20:40 h, March 13th). As for lower head failure, there is still large uncertainty in predicting lower head failure time with Larson-Miller creep rupture model in the current MELCOR modeling.

Evaluation of Alternate Water Injection Cooling for Accident Conditions in Spent Fuel Pool Using MAAP Code

Evaluation of Alternate Water Injection Cooling for Accident Conditions in Spent Fuel Pool Using MAAP Code

Evaluation of recycle gas injection on CO2 enhanced oil recovery and associated storage performance

An enhanced oil recovery (EOR) technique comprising the alternate injection of gas (CO2) and water, commonly referred to as water alternating gas (WAG) flooding, is currently ongoing at an oil field in the northeastern Powder River Basin (PRB), where 4 million barrels (MMbbl) of oil were produced between May 2013 and September 2017. During WAG flooding, a large amount of CO2, which contains some impurities, is produced at the surface with the recovered oil and reinjected into the reservoir to minimize the amount of purchased CO2. The concentration of these impurities in the CO2, which are dominated by CH4, is a key parameter in the design of miscible CO2 flooding of an oil reservoir and in the quantitative assessment of the associated storage of CO2 that occurs in the reservoir. For a given oil and reservoir temperature, the CO2–oil minimum miscibility pressure (MMP) is strongly and adversely affected by the presence of CH4, the concentration of which varies with time and operational conditions, such as injection pressure, flooding pattern, and injection scheme (i.e., continuous CO2 injection or WAG). To capture the full range of potential variation in the MMP caused by the presence of CH4, a series of laboratory experiments were conducted to determine CO2–oil MMP with different mole percentages of CH4 in the CO2. All of the experiments were performed at reservoir temperature (108 °F) using the VIT (vanishing interfacial tension) method. Results showed that MMP increases from 1403 to 4085 psi as the mole percentage of CH4 in the CO2 increases from 0% to 100%. To assess the impact of this variation in MMP on the oil recovery performance in the field, a history-matched, compositional reservoir simulation model was used to predict the oil production performance for a WAG flood using CO2 that contained a range of CH4 concentrations. The reservoir simulations examined the effects of permeability heterogeneity, fluid crossflow, and phase behavior on the oil displacement performance in three-dimensional space over time. Simulation results indicated that CO2 floods using a limited range of CO2–CH4 mixtures could still maintain multiple-contact miscibility and result in effective EOR. In addition, the ability to reinject produced CO2–CH4 mixtures as is, without removal of the CH4, ensured that this approach to EOR would continue to be cost-effective.

Fukushima Unit 2 Accident Simulation With MELCOR 2.1

A VTT Fukushima Daiichi Unit 3 (1F3) method for estimation of liquids and consequences of releases (MELCOR) model was modified to simulate the Fukushima Daiichi Unit 2 (1F2) accident. Five simulations were performed using different modeling approaches. The model 1F2 v1 includes only the basic modifications to reproduce the 1F2 accident. The model 1F2 v2 includes the same modifications used in 1F2 v1 plus the wet well (WW) improvement. In the 1F2 v3 model, the reactor core isolation cooling (RCIC) system logic was modified to avoid the use of tabular functions for the mass flow inlet and outlet. Because of this analysis, it is concluded that there is a strong dependency on parameters that still have many uncertainties, such as the RCIC two-phase flow operation, the alternative water injection, the suppression pool (SP) behavior, the rupture disk behavior and the containment failure modes, which affect the final state of the reactor core.

Study of rescue measure of Kuosheng BWR power plant to cope with Fukushima-type accident

Because of the accident in the Fukushima Dai-ichi nuclear power plant on March 11, 2011, the Taiwan Power Company developed the ultimate response guidelines for the owned nuclear power plants to cope with the Fukushima-type event. The guidelines had the DIVing strategy to prevent the core damage, the hydrogen generation, and the public evacuation. The strategy performed the depressurization and injection of the reactor pressure vessel and the venting of the containment simultaneously to keep the peak cladding temperature of the core fuels below 1500 °F (1088.7 K) The MAAP5 and RELAP5 models of the Kuosheng BWR/6 nuclear power plant of the Taiwan Power Company were used to assess the effectiveness of the guidelines. Based on the results of the code calculations, it was concluded that the guidelines could be used successfully to cope with the Fukushima-type event. And according to the results of the comparisons, the MAAP5 simulations were similar to the RELAP5 calculations. Based on the RELAP5 simulation results, if three safety relief valves were used to do the vessel controlled depressurization, the peak cladding temperature of the core fuels might increase and the concern of the core fuel safety might be needed. According to the sensitivity study results, if the initiation pressure of the vessel emergency depressurization was higher than 40 kgf/cm2 (4.03 MPa), the minimum vessel alternate water injection flow would have the significant increase.