Overcoming Hydraulic Fracturing Challenges in High Temperature and Tight Gas Reservoirs of Saudi Arabia with an Enhanced Fracturing Fluids System

Hydraulic fracturing has been an important aspect on the successful exploitation of gas sandstone formations in Saudi Arabia. During the past decade, conventional formations were stimulated successfully with traditional low to moderate temperature borate crosslinked based fracturing fluids. As the development of the existing fields continue into deeper formations and the exploration activities are inclined toward unconventional reservoirs, new challenges are experienced from lower permeabilities and higher temperatures. The conventional borate crosslinked gels are no longer the choice of fracturing fluids for extreme bottom-hole conditions. To overcome these challenges, an improved, salt-compatible, low-polymer, organometallic crosslinked-gel (CMHPG) as fracturing fluid has been introduced for high-temperature (HT) wells. The novel HT fluid provides excellent proppant transport capabilities at temperatures ranging from 60 to 375 °F, while using fracture fluid requires less base polymer that results in less formation damage and higher retained conductivity of the propped fracture. This property is especially valuable in low-permeability reservoirs, where extended fracture lengths are typically required to maximize reservoir contact and enhance production. Additionally this fluid has been enhanced with a microemulsion surfactant to obtain a higher load recovery and also a novel clay stabilizer specially designed for tight gas and shale formations. This paper addresses the successful application of this enhanced fracturing fluid in HT and tight gas wells of Saudi Arabia along with its post-treatment evaluation comparing dimensionless productivity index between fracture treatments with new and conventional fracturing fluids.