Hydraulic fracturing optimization requires addressing numerous challenges for various reservoirs. The proposed paper presents a case study of a thinly-interbedded tight sandstone reservoir with a very low net to gross ratio in a field, onshore Australia. A geomechanical model was developed for hydraulic fracturing optimization. The low contrast in stress and rock mechanical properties between the reservoir and bounding formations posed a challenge to achieve a fracture that was confined to the pay zone, and particularly one that avoided fracturing the underlying water-bearing zone. Optimization modelling showed that the oil flow rate increased proportionately with fracture length and conductivity up to certain threshold values, above which the production benefit diminished. An injection schedule was optimized for production using a proppant and a fracturing fluid both suitable for the reservoir conditions to achieve the optimum or near-optimum fracture length and conductivity, efficient proppant transport, and confinement of the fracture above the water-bearing zone. Production prediction through the optimized fracture design in a vertical well showed a potentially uneconomic recovery. Multi-stage fracturing of a 1,500 m horizontal well was investigated as an alternative completion scenario for which the number of transverse fractures was optimized. The spacing between such horizontal wells was also investigated and optimized based on efficient drainage that could be achieved by the horizontal well with the optimum number of transverse fractures. Optimally spaced horizontal wells with an optimum number of transverse fractures were found as the most recoverable development strategy; use of injection wells for lateral sweeping and pressure maintenance, and artificial lift is likely to increase recovery further whereas infill wells are likely to be necessary for incremental production.

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