Optimization of Fluid Lab Testing for Conventional Proppant Fracturing Applications in HT Reservoirs

Abstract

Abstract Fracturing operations in low to medium permeability reservoirs tend to be driven by efficiency and costs of the operations. At the same time, fracture geometry and conductivity need to be optimized to ensure economical field development. The objective of this paper is to revise and enhance fluid design lab testing process in high-temperature (HT) reservoirs by dealing away with fluid over-designing practices through accurate fracturing modeling which will significantly reduce reservoir damage. Fluid design practices often assume a safety factor for the fluid exposure duration to be equal to or greater than the full treatment duration. It is also commonly required to match the bottom hole static temperature (BHST) for the whole lab test duration with a minor focus on the overall tubulars and reservoir cooldown during later stages of the treatment. The advanced planar 3D simulator was used to create sensitivity studies for the temperature profile inside the fracture during placement. Results were then used in the experimental lab testing to optimize the fluid recipe based on new temperature profile and time of exposure. Advanced software modeling and rheological studies identified several ways to avoid fluids overdesign, leaving behind cleaner reservoirs without imposing operational risks. The sensitivity analysis revealed that depending on several parameters such as the fluid leak-off severity, volume, and rate of the treatment; the amount of polymer load can reach 30% and higher when accounting for the cool down effect and reduced fluid exposure time. For the fluid breaking ability at lower temperatures, it is also critical to mimic realistic temperature profile inside the fracture for several hours after the treatment. The studies suggest that the largest impact is expected for extreme HT conditions in relatively higher permeability and prolific formations with fluid efficiency values of 40% and lower. These reservoirs will require a significant amount of pad to compensate for leakoff and considerable amount of proppant to cover the entire interval. In these cases, maximum fluid exposure will be limited by 50-70% of the entire treatment time and the cool down effect prior to proppant entry will be considerable. Considering middle eastern applications, this type of reservoir is not a minor number of cases; hence the new methodology would be beneficial to consider and implement across the region. This paper will reveal an optimized approach to the fracturing fluids lab testing and will help to shape the future of fracturing treatments in HT reservoir conditions in a way that will not only reduce the fracturing cost but will also help to reduce reservoir damage hence improving well productivity.