RESUMEN
Polymer flooding has drawn more and more attention in the world for its high incremental oil recovery factor and relative low costs compared with water flooding and other chemically enhanced oil recovery techniques. However, for many oilfields, such as Daqing Oilfield, China, that have already been flooded with polymers, how to further improve recovery remains a big problem. Traditional intralayer, interlayer and plane heterogeneity studies cannot accurately characterize the remaining oil distribution after polymer flooding. To solve this problem, we established a method to quantitatively describe the reservoir's architecture. Then, the architecture elements were dissected hierarchically and the interface of each architecture level in Daqing Oilfield was identified. The distribution pattern and development potential of the remaining oil after polymer flooding under the influence of reservoir architecture was analyzed. The results show that, regarding the sedimentary process from north to south in Daqing Oilfield, the channel becomes narrower, the thickness decreases, the point bar's width increases and the thickness of the meandering river decreases. The braided bar scale becomes larger and the thickness becomes smaller in the braided river. According to the reservoir's architecture, the remaining oil was divided into four categories of plane remaining oil (abandoned channel occlusion type, interfluvial sand body occlusion type, inter-well retention type and well pattern uncontrollable type) and three types of vertical remaining oil (in-layer interlayer occlusion type, rhythm type and gravity type). About 40% of the original oil in place (OOIP) of Daqing Oilfield has not yet been produced, which indicates that there is great potential for development. This study is important for improving oil recovery in polymer-flooded reservoirs.
RESUMEN
A unique experiment design is proposed to study the asphaltene precipitation caused by multiple contact processes during gas injection. The newly proposed experiment quantified the asphaltene precipitation at different methane contact steps. Twenty times methane contacts and corresponding asphaltene precipitation states are measured using a light scattering setup under reservoir condition. The amount of the asphaltene precipitation, the composition changes, and the physical properties changes are measured for the 20 times methane contacts. After verifying the asphaltene precipitation in the static experiments, the formation damage caused by the asphaltene precipitation is studied by core flooding tests for three different permeability cases. We found that the primary asphaltene precipitation mechanism in the multiple contact process during methane injection is not the composition change caused by methane extraction. The methane-induced asphaltene stability loss during the multiple contact process is vital. The size and the structure of asphaltene precipitation particles in the crude oil change with the methane contacts. We found that the mechanism of permeability reduction caused by asphaltene precipitation is different depending on the porous media pore throat size and the asphaltene precipitation particle size. Under our experimental condition, the asphaltene precipitation acts as a conformance control method, leading to well-distance optimization considerations in field applications.
RESUMEN
Polymer flooding is an effective enhanced oil recovery (EOR) technology used in Daqing Oilfield. Microscopic distribution of remaining oil in polymer-flooded reservoirs is more complicated in comparison with waterflooded reservoirs. In this paper, UV excitation, frozen section-laser confocal technology, and three-dimensional reconstruction technology were employed to investigate the distribution law and occurrence state of the microscopic remaining oil in polymer-flooded Daqing Oilfield. With these methods, the occurrence states of the microscopic remaining oil distribution in different washing degrees and displacement locations were analyzed, and the remaining oil distribution before and after polymer flooding was compared quantitatively. The changes and microscopic distribution characteristics of crude oil components in the process of polymer flooding were clarified, and the relationship between clay minerals and the microscopic remaining oil distribution was discussed. Based on the statistical analysis of experimental results, the remaining oil of the free state decreases gradually, while the remaining oil of the bound state increases as the washing degree increases. In addition, the remaining oil in the distributary line is more enriched than the mainstream line after polymer flooding. Compared with waterflooding, the remaining oil of the free state becomes more, while the remaining oil of the bound state becomes less after polymer flooding. The frozen section-laser confocal experimental results also indicate that the proportion and distribution characteristics of the remaining oil components have been changed, and heavy components increase while light components decrease in the polymer-flooded stage. This research performs the quantized characterization and detailed analysis of remaining oil systematically and lays the foundation for remaining oil prediction and potential tapping in polymer-flooded reservoirs.
RESUMEN
To determine original gas-in-place, this study establishes a flowing material balance equation based on the improved material balance equation for shale gas reservoirs. The method considers the free gas in the matrix and fracture, the dissolved gas in kerogen, and the pore volume occupied by adsorbed phase simultaneously, overcoming the problem of incomplete consideration in the earlier models. It also integrates the material balance method with the flowing material balance method to obtain the average formation pressure, eliminating the problem with the previous method where shutting down of wells was needed to monitor the formation pressure. The volume of the adsorbed gas on the ground is converted into volume of the adsorbed phase in the formation using the volume conservation method to characterize the pore volume occupied by the adsorbed phase, which solves the problem of the previous model that the adsorbed phase was neglected in the pore volume. The model proposed in this study is applied to the Fuling Shale Gas Field in southwest China and compared with other flowing material balance equations, and the results show that the single-well control area calculated by the model proposed in this study is closer to the real value, indicating that the calculations in this study are more accurate. Furthermore, the calculations show that the dissolved gas takes up a large fraction of the total reserves and cannot be ignored. The sensitivity analyses of critical parameters demonstrate that (a) the greater the porosity of the fracture, the greater the free gas storage; (b) the values of Langmuir volume and TOC can significantly affect the results of the reservoir calculation; and (c) the adsorbed phase occupies a smaller pore volume when the Langmuir volume is smaller, the Langmuir pressure is higher, or the adsorbed phase density is higher. The findings of this study can provide better understanding of the necessity to take into account the dissolved gas in the kerogen, the pore volume occupied by the adsorbed phase, and the fracture porosity when evaluating reserves. The method could be applied to the calculation of pressure, recovery of free gas phase and adsorbed phase, original gas-in-place, and production predictions, which could help for better guidance of reserve potential estimations and development strategies of shale gas reservoirs.
