Water alternating hydrocarbon gas miscible flooding integrates the improved microscopic displacement efficiency of gas flooding with the increased macroscopic sweeping volume of water injection and has been applied as an enhanced oil recovery method. The purpose of this research is to analyze effects of developmental factors on a water alternating hydrocarbon gas miscible flooding. A low permeability reservoir sector model with one producer and two injectors is conducted to determine the optimal dynamic parameters in water alternating hydrocarbon gas miscible flooding. Firstly, effects of three injection methods are analyzed. Then, factors of water alternating hydrocarbon gas miscible flooding discussed in this research include components of hydrocarbon gas, WAG ratios, and gas injection rates. Three injection methods, continuous water flooding, continuous hydrocarbon gas flooding and water alternating hydrocarbon gas miscible flooding, have an impact on the displacement efficiency and sweep efficiency, which effect the oil recovery. The mole percentage of C1 in injected gas is related to the minimum miscible pressure, which directly affects production performances of hydrocarbon gas miscible flooding. The value of this factor is scaled from 75% to 90% to discover its effect on oil recovery in this sector model. Different WAG ratios act differently in gas breakthrough and pressure maintenance. WAG ratios are respectively 1:5 (one month gas injection followed by five months water injection), 3:6 and 6:6 in this research. Gas injection rates are set from 5,000Mscfd to 15,000Mscfd to study their impacts on production performances. Results show that water alternating hydrocarbon gas miscible flooding gains higher displacement efficiency than continuous waterflooding and performs better in sweep efficiency than continuous hydrocarbon gas flooding. Under the similar condition, the mole percentage of C1 acts differently on reservoir performances. Along with the decrease of C1 mole percentage, oil recovery raises from 49.44% to 51.43%. Based on this, simulation schemes with different WAG ratios which impact the gas injection volume are carried out for further study. Compares to the results of 1:5 WAG ratio, and 3:6 WAG ratio, 6:6 WAG ratio contributes to a longer production plateau and a higher oil recovery accordingly. Furthermore, gas injection volume is related to the reservoir potential, and through observations, simulation scenario with 6:6 WAG ratio offers a sustainable higher production and shows higher potential in this research. When other factors stay unchanged, gas injection rate as the only variable raises from 5,000Mscfd to 15,000Mscfd, the oil recoveries of these simulation schemes increase. However, the increments of the oil recoveries gradually decline, which demonstrates that an appropriate injection gas rate can achieve a sufficient production performance and obtain a maximum economic benefit. Based on previous findings in this study, we can conclude that through studies of various factors that influence oil recovery, the results can be applied to determine an optimal strategy for the reservoir developed by hydrocarbon gas miscible flooding. In addition, it is also adapted to develop reservoirs by other WAG methods, such as carbon dioxide and non-hydrocarbons.
A new type of fracture which was caused by the waterflooding process in the low-permeability reservoirs has attracted the engineers’ great attention in China recently. This new type of fracture, named the waterflood-induced dynamic fracture, has a significant impact on the swept volume of water flooding and the distribution of remaining oil, and therefore, directly affects the reservoirs development. However, because of the special features of these fractures, such as the morphological changes, the time-varying permeability and vulnerable to the production performance, it is almost impossible to characterize them accurately in the normal reservoir simulation. In order to describe the waterflood-induced dynamic fracture, a new model was established in this paper. By overlapping the dynamic fracture model and the psudo-tenser permeability model to the dual porosity model which consists of a set of disconnected matrix blocks and a network of connected fractures, a new dynamic hybrid dual porosity model was derived. Compared with the conventional dual porosity model, the dynamic hybrid dual porosity model allows the property of the fracture system to change with time, so that the above problems can be solved very well. Through the numerical simulation of a typical low-permeability oilfield by using the established model, the evolution process of the waterflood-induced dynamic fracture including opening, extending and closing, and its impact on the development of the low-permeability reservoir were carefully studied. The simulation results show that the dynamic fracture grows continuously and slowly throughout the entire life of the oilfield development. And it has significantly narrowed the water flooding swept range, and reduced the vertical producing degree of water flooding to a certain extent, which is very consistent with the production performance data of this oilfield. Meanwhile, the precision accuracy of simulation result has been observably improved by using this new model, which indicates that the model can precisely depict the changes of the dynamic fracture both in its morphology and its properties. Furthermore, the established dynamic hybrid dual porosity model could be used to elucidate the mechanism of the evolution of the waterflood-induced dynamic fracture and so forth. Therefore, it provides an important technical means for the study of the effective development and prompt adjustment of water injection policy of low-permeability reservoirs.
Reservoir simulation has come a long way since its birth in the 1950s and now is an important tool for reservoir engineers to predict oil and gas production and optimize reservoir management. In the past, many existing models were developed to simulate fluids with a specific fluid characterization such as black oil, compositional and thermal models. Today, the need for optimizing reservoir life with different recovery techniques and different fluid characterizations is urgent to fully evaluate oil and gas fields assets. In this paper, a flexible general purpose model has been developed for multiphase isothermal or thermal compositional flow simulation in porous media, including formulations, phase behavior calculation, various numerical techniques. Based on general mass balance equations and energy balance equations, a mass variable set has been chosen for the generality for all types of fluids (black-oil, compositional and thermal) to ensure that each grid block has the same amount of primary unknowns and it is convenient for Jacobian matrix construction. The model decouples fluid and formulation from the rest of simulator and makes is possible to model different reservoir physics in one single simulator. The model have tested and validated on various standard comparative benchmark problems like black-oil model, compositional model as well as large complex field cases with over one million grid blocks and an actual reservoir simulation. The test results show that the simulator is comparable with current commercial simulators in accuracy and speed. When different recovery techniques are used in a reservoir life cycle, the model is more efficient and accurate without the need of switching simulators. The generic and modular design architecture provides convenience for extensions of modeling additional flow processes and implementing new numerical solution methods. Developing a general purpose reservoir simulator is the main focus in state-of-the-art reservoir simulation research. The proposed general purpose model for multiphase compositional flow simulation in this paper is one step closer to the goal.
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