HT Fracturing Fluid in Stimulating Saudi HTHP Gas Wells: Lab Results and Field Cases

Abstract

Abstract The Carbonate Field, one of the world's largest oil and gas fields, consists of different reservoirs with different lithology where reservoir temperature ranges from 280 °F to 330 °F. Several high temperature, high pressure (HTHP) wells were hydraulically fractured in "Reservoir A," a gas bearing formation, in the Carbonate Field in Saudi Arabia. High temperature reservoirs present a challenge to successfully fracture because a novel fracturing fluid is necessary to sustain the high temperature. Reservoir A is a sandstone gas-bearing reservoir associated with liquid condensate that in most cases requires hydraulic fracturing to enhance productivity and control sand production. Its high temperature and pressure creates technical and operational challenges. The harsh formation environment requires a prolonged fluid stability to ensure stimulation effectiveness. Once the bottom-hole static temperature (BHST) is above 300 °F, borate-based crosslinked fracturing fluid can become unstable causing a rapid viscosity loss and eventually a poor proppant carrying capacity. Metal-crosslinked fracturing fluids are well-known for high viscosity. Zirconates and Titanates are the main metal complexes of guar polymers. CarboxyMethylHydroxyPropyl Guar (CMHPG) crosslinked with Zirconium crosslinker is the most common fluid used in elevated bottom-hole applications as they develop excellent viscosity and proppant carrying capacity in these high temperature and pressure environments. Zirconate crosslinked fluids have been successfully pumped in wells where bottom-hole temperature exceeded 400 °F and resulted in a significant production increase (Stolyarov and Dean, 2011). The technical stimulation approach in Reservoir A is to induce a wide and very conductive fracture to mitigate the pressure drop the producing fluid experiences as it reaches wellbore to prevent condensate banking. It is a vital to have a stable fluid to generate the right width to accept the higher proppant concentration. This paper includes laboratory testing evaluation of fracturing fluid stability and breaker optimization. It will also show how the pressure falloff analysis was performed prior to the main frac to calibrate the fluid efficiency in the frac model and optimize fracture geometry. Post-treatment net pressure matching was conducted to predict the final fracture geometry and then nodal analysis was performed using the created fracture geometry and actual flowback data to further validate the incremental production increase after the treatment.