Residual oil distribution characteristic of fractured-cavity carbonate reservoir after water flooding and enhanced oil recovery by N2 flooding of fractured-cavity carbonate reservoir
“…Jin et al (2015) carved the fracture network and fracture-cave network on the surface of full-diameter carbonate cores and reviewed polymer gel injection for profile control in different well connection patterns. Yuan et al (2015) built a 2-D visual fracture-cavity carbonate reservoir model based on the distribution and connection of fractures and caves in the reservoir. The remaining oil was studied after water flooding and N 2 flooding potential was evaluated.…”
Gas injection serves as a main enhanced oil recovery (EOR) method in fractured-vuggy carbonate reservoir, but its effect differs among single wells and multi-well groups because of the diverse fractured-vuggy configuration. Many researchers conducted experiments for the observation of fluid flow and the evaluation of production performance, while most of their physical models were fabricated based on the probability distribution of fractures and caves in the reservoir. In this study, a two-dimensional physical model of the karst fault system was designed and fabricated based on the geological model of TK748 well group in the seventh block of the Tahe Oilfield. The fluid flow and production performance of primary gas flooding were discussed. Gas-assisted gravity flooding was firstly introduced to take full use of gas-oil gravity difference, and its feasibility in the karst fault system was examined. Experimental results showed that primary gas flooding created more flow paths and achieved a remarkable increment of oil recovery compared to water flooding. Gas injection at a lower location was recommended to delay gas breakthrough. Gas-assisted gravity flooding achieved more stable gas-displacing-oil because oil production was at a lower location, and thus, the oil recovery was further enhanced.
“…Jin et al (2015) carved the fracture network and fracture-cave network on the surface of full-diameter carbonate cores and reviewed polymer gel injection for profile control in different well connection patterns. Yuan et al (2015) built a 2-D visual fracture-cavity carbonate reservoir model based on the distribution and connection of fractures and caves in the reservoir. The remaining oil was studied after water flooding and N 2 flooding potential was evaluated.…”
Gas injection serves as a main enhanced oil recovery (EOR) method in fractured-vuggy carbonate reservoir, but its effect differs among single wells and multi-well groups because of the diverse fractured-vuggy configuration. Many researchers conducted experiments for the observation of fluid flow and the evaluation of production performance, while most of their physical models were fabricated based on the probability distribution of fractures and caves in the reservoir. In this study, a two-dimensional physical model of the karst fault system was designed and fabricated based on the geological model of TK748 well group in the seventh block of the Tahe Oilfield. The fluid flow and production performance of primary gas flooding were discussed. Gas-assisted gravity flooding was firstly introduced to take full use of gas-oil gravity difference, and its feasibility in the karst fault system was examined. Experimental results showed that primary gas flooding created more flow paths and achieved a remarkable increment of oil recovery compared to water flooding. Gas injection at a lower location was recommended to delay gas breakthrough. Gas-assisted gravity flooding achieved more stable gas-displacing-oil because oil production was at a lower location, and thus, the oil recovery was further enhanced.
“…In order to ensure the fault sealing ability, the production well is generally drilled 50-80 m away from the top fault boundary [5,6]. The attic oil is consequently formed due to the lack of water flooding control in the top structure at the high water cut stage [7]. Attic oil is considered as the remaining oil located at the top of a reservoir, which is above the structurally highest well in a dipping reservoir [8,9].…”
As the mature oil fields have stepped into the high water cut stage, the remaining oil is considered as potential reserves, especially the attic oil in the inclined fault-block reservoirs. A novel assisted gas–oil countercurrent technique utilizing gas oil countercurrent (GOC) and water flooding assistance (WFA) is proposed in this study to enhance the remaining oil recovery in sealed fault-block reservoirs. WFA is applied in our model to accelerate the countercurrent process and inhibit the gas channeling during the production process. Four comparative experiments are conducted to illustrate enhanced oil recovery (EOR) mechanisms and compare the production efficiency of assisted GOC under different assistance conditions. The results show that WFA has different functions at different stages of the development process. In the gas injection process, WFA forces the injected gas to migrate upward and shortens the shut-in time by approximately 50% and the production efficiency improves accordingly. Compared with the basic GOC process, the attic oil swept area is extended 60% at the same shut-in time condition and secondary gas cap forms under the influence of WFA. At the production stage, the WFA and secondary gas cap expansion form the bi-directional flooding. The bi-directional flooding also displaces the bypassed oil and replaced attic oil located below the production well, which cannot be swept by the gas cap expansion. WFA inhibits the gas channeling effectively and increases the sweep factor by 26.14% in the production stage. The oil production increases nearly nine times compared with the basic GOC production process. The proposed technique is significant for the development of attic oil in the mature oil field at the high water cut stage.
“…Previous studies showed that the fractured-vuggy carbonate reservoirs are largely dependent on primary depletion and natural water flooding for exploration, and the oil recovery factor is quite low with only 6.0%~8.0% 10 .Figure 1Different patterns of fractured-vuggy medium (Lyu et al . 13 ). ( a ) fracture network; ( b ) isolated cave; ( c ) cave-fracture-cave; ( d ) pore-fracture-pore; ( e ) pore-fracture-cave; ( f ) cave network.…”
Section: Introductionmentioning
confidence: 99%
“…Different patterns of fractured-vuggy medium (Lyu et al . 13 ). ( a ) fracture network; ( b ) isolated cave; ( c ) cave-fracture-cave; ( d ) pore-fracture-pore; ( e ) pore-fracture-cave; ( f ) cave network.…”
Section: Introductionmentioning
confidence: 99%
“…11,12 and Yuan et al . 13 carried out laboratory experiments to analyze the residual oil characteristics in fractured-vuggy carbonate reservoirs after water flooding and N 2 flooding by creating specific physical models. Starting from the practice situation of Tahe oilfield, and integrated dynamic evaluation of depletion drive performance, Rong et al .…”
Cyclic water huff and puff (CWHP) has proven to be an attractive alternative to improve oil production performance after depletion-drive recovery in fractured-vuggy carbonate reservoirs. However, due to the impact of strong heterogeneity, multiple types of fractured-vuggy medium, poor connectivity, complex flow behaviors and oil-water relationship, CWHP is merely suitable for specific types of natural fractured-vuggy medium, usually causing a great difference in actual oil-yielding effect. It remains a great challenge for accurate evaluation of CWHP adaptability and quantitative prediction of production performance in fractured-vuggy carbonate reservoir, which severely restricts the application of CWHP. For this study, we firstly enable the newly developed fuzzy grey relational analysis to quantify the adaptability of CWHP. With production history of several targeted producers, the accuracy of the proposed method is validated. Based on the traditional percolation theory and waterflood mechanisms in various types of fractured-vuggy medium, a quantitative prediction model for cyclic water cut fwp and increased recovery factor ΔR is presented. The CWHP production performance is discussed by using the Levenberg-Marquardt algorithm for history matching. With a better understanding of the fwp ~ ΔR curve characteristics in different types of fractured-vuggy medium, proper strategies or measures for potential-tapping remaining oil are provided. This methodology can also offer a good basis for engineers and geologists to develop other similar reservoirs with high efficiency.
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