Successful Application of Clean Fracturing Fluid Replacing Guar Gum Fluid to Stimulate Tuffstone in San Jorge Basin, Argentina

Abstract Hydroxypropyl guar (HPG) fluid, which is widely used in San Jorge Basin due to it is inexpensive and able to carry high concentration proppants, has more residue to damage matrix. As the permeability of tuffstone is very low, fracturing fluid that are low-damaging to the proppant pack and formation are becoming important. This paper presents the development of a low damage fracturing fluid instead of HPG and the results of successful field applications. This clean fracturing fluid uses a low-residue polymer crosslinked with zirconium having a pH of less than 10 to minimize damage and residue encountered using other fluids. The fluid was tested for rheological properties and retained permeability which was used to evaluate the compatibility of two types of fracturing fluids with formation cores at reservoir temperature. The use of regain permeability was evaluated fluids. In addition, broken fluids were tested to figure out the amount of residue. The clean fracturing fluid was expected to generate low damaging effects on tuffstone in order to increase reservoir productivity. During development, the fluid remained stable for approximately 2 hours at 120°C with a gel loading of 5 kg/m3. The target reservoir temperature ranges from 90°C to 120°C. Additional testing optimized gel loading at 4 kg/m3. The viscosity of crosslink fluids after 1 hour shear was stable about 60mPa·s at 170 sec−1, which was much lower than HGP with 200mPa·s. The fluid suspended the proppant for approximately 2 hours. Less than 120 mg/L residue concentration was formed after fluid breakdown, which was much lower than the residue generated by HPG. A regained permeability of 88% was obtained from a sandstone core, which demonstrates the low-damaging nature of the fluid. However, the regained values of HPG were below 50% that means more than half of fracture conductivity and matrix permeability surround fracture will be lost, even HPG could carry higher concentration proppant into fracture. Four vertical wells in same work area were designed and executed successfully to compare two fluids. The well stimulated by low damage fluid got very good production, which was 2-8 times of adjacent wells. This work provides critical insights into understanding the performance of using clean fracturing fluid to mitigate formation damage in tight formations. It is an excellent candidate for fracturing operations and can help operators maintain low costs per barrel of oil equivalent.