Fractured-vuggy carbonate reservoirs are characterized by large differences in reservoir scale, strong spatial discreteness, complex fracture-vug connectivity between wells, and diverse fluid flow patterns. The low control degree of fractures and vugs results in uneven producing of reserves and different water/gas flooding effects. The regular and irregular well patterns for conventional sandstone reservoirs are not applicable to fractured-vuggy carbonate reservoirs. Therefore, it is necessary to establish a well pattern construction and optimization method that matches the characteristics of fractured-vuggy carbonate reservoirs. By combining physical simulation experiments with theoretical analysis and following the idea of constructing a “three-dimensional” and “systematic” well pattern, the theoretical connotation of spatially structural well patterns is enriched, and the fundamental understanding of gravity displacement theory in the construction of spatially structural well patterns is deepened. A well pattern design method and a 6-step well pattern construction process are established, focusing on fracture-vug structures, connectivity, reserves producing, energy conditions, and injection-production structures. It is concluded that the difference in fluid density is the dominant factor of gravity displacement, the potential difference in the fracture-vug connectivity structure is the important driving force for vertical displacement, and the displacement speed difference between primary and secondary channels is the key to vertical balance and serves as an efficiency mechanism for EOR of fractured-vuggy reservoirs with spatially structural well patterns.
For the reservoirs in late development stage with ultra-high water cut, which exhibit significant difference in the oil-water two-phase flow capacity and strong dynamic reservoir heterogeneity, the injector interval subdivision method based on static parameters such as permeability and the interval water allocation method using empirical analysis are insufficient to meet the requirements of precise development of multi-layered sandstone reservoirs. Through theoretical analysis, physical simulation, and numerical modeling, the flow behaviors in the oilfields in late development stage with ultra-high water cut were further understood. A flow resistance calculation model for reservoir layers was developed, and aiming at minimizing the variation coefficient of flow resistance in single wells, a method for water injection interval optimization based on flow resistance was established. Additionally, by constructing coefficients of remaining reserves, reasonable injection-production ratio, relative water injection efficiency, and water cut rising rate for intervals, a quantitative adjustment method for water injection in the intervals with ultra-high water cut was developed. This method allows for quantitative water injection under conditions involving multiple wells, multiple layers, and complex injection-production relationships. The method was tested 237 times in wells of a typical block, with a decrease in initial water cut by 0.14%, demonstrating a satisfactory performance in both water control and oil increasement.
In order to clarify the variation in the conductivity of different types of sedimentary rocks after fracturing, post-frac conductivity tests were conducted on the sedimentary rocks such as turbidite, beach-bar sandstone, and sandy conglomerate to identify the relationship between lithology and conductivity, and a conductivity model was constructed. The conductivity model was then incorporated into the primary fracture pressure control equation to obtain an analytical solution for primary fracture pressure. A semi-analytical model for predicting the productivity of multi-stage fractured horizontal wells was developed by using the distributed volume source method. The new productivity model was applied to the tight oil reservoirs in the Chaoyanggou oilfield in the periphery of Changyuan, Daqing. It is found that the calculation errors from a numerical model, a productivity model without considering lithology and the new productivity model considering lithology are 6.5%, 22.7% and 4.6%, respectively. The new model focuses on the impact of different sedimentary rock lithologies on productivity, which can improve the accuracy of productivity prediction for tight oil reservoirs.
The massive sandstone reservoirs with bottom water in the Tahe oilfield are characterized by relatively thin oil layers. After oil wells are put into production, water breakthrough, water-cut rise, and production decline occur rapidly, posing challenges for stable production. Through the analysis of reservoir development characteristics, the water-cut rise patterns of wells were classified, and the remaining oil distribution and its influencing factors were determined. The results indicate that the main factors affecting the distribution of remaining oil in bottom-water reservoirs are structure, interlayer, reservoir heterogeneity and development methods. Based on the distribution of remaining oil in bottom-water reservoirs in the high water-cut period, effective potential tapping strategies were proposed to improve development efficiency, including flow adjustment by controlling fluid, natural gas flooding, and CO2 flooding. Numerical simulations and field practices have demonstrated satisfactory results of these strategies, which provide valuable references for the development of similar reservoirs.
There are various types of reservoirs in the fault-controlled reservoir system in the Shunbei No.4 strike-slip fault zone, and the spatial positions of the reservoirs affect the connectivity of the reservoir system and restrict the production of oil wells in different locations. A method of pre-drilling evaluation on the connectivity of target reservoir system was proposed to evaluate the connectivity of fault-controlled reservoir system in the middle section of the Shunbei No.4 strike-slip fault zone. The results show that the fault-controlled reservoir system in the middle Shunbei No. 4 strike-slip fault zone can be divided into 4 compartmental units. The connectivity rates of internal caverns of the 4 compartmental units all exceed 50%, with extended high-angle fractures, large cumulative thickness of vertical caves, and strong connectivity. The favorable reservoirs in compartmental units 3 and 4 indicate high probabilities in obtaining higher production.
The reservoirs with bottom water in the Luliang oilfield are characterized by multiple thin and scattered oil layers, strong interlayer heterogeneity, extra-high watercut of oil wells, and low efficiency of layered water injection. The oilfield is facing challenges such as unclear distribution of remaining oil and difficult control of water injection. In response to the current water injection status of the multilayered sandstone reservoirs in the Luliang oilfield, a new method of water injection control was established based on the interwell numerical simulation model (INSIM) and by using geological congnition, logging data and testing data. The new method helps realize a rapid simulation evaluation and injection-production parameter optimization for layered water injection in well groups with different formation coefficient ranges. This method allows for the analysis of vertical and horizontal water injection in multilayered reservoirs, and also the dynamic simulation of natural production splitting. The application to a typical well group in the L9 reservoir of the Luliang oilfield demonstrates an estimated increase in the cumulative oil production by 3.2×104 m3, a decrease in the cumulative injected water by 3.9×104 m3, and a decline in the water cut in the well block by 6.1%. Thus, the efficiency of layered water injection is improved, and the effects of production increasing and water reduction are enhanced. The method may serve as a reference for layered water injection control and potential tapping in multilayered sandstone reservoirs.
