ABSTRACT

The decline in oil production due to aging wells and formation damage has become a critical challenge in the petroleum industry. This study focuses on the design of hydraulic fracturing to improve Well X's productivity in the Telisa Formation, Central Sumatra Basin. The research utilized FracCADE 7.0 software to simulate hydraulic fracturing scenarios and optimize fracture geometry and conductivity. The parameters investigated included variations in fracturing fluid volume, proppant types, and injection methods, culminating in 12 simulation scenarios. The geomechanical analysis revealed that the Telisa Formation, dominated by low Young’s modulus (<3×10⁶ psi) and low Poisson’s ratio, is favorable for fracturing, as it tends to generate wider fractures at lower pumping pressures. However, higher Young's modulus layers at greater depths showed the potential for longer but narrower fractures, albeit requiring higher pumping pressures. These characteristics guided the selection of fracturing intervals and operational parameters to optimize stimulation results. The results showed that the optimal scenario utilized 32,239 gallons of fracturing fluid, Brady Sand as the proppant, and the Proppant Concentration Step-Wise Increasing (PCSI) injection method. This configuration produced fractures with a half-length of 171 ft, width of 0.149 inches, height of 253.3 ft, and fracture conductivity of 13,592 mD.ft, resulting in a Fold of Increase (FOI) of 6.82. Economically, this scenario required a total cost of $574,576.47 and achieved a pay-out time (POT) of 48 days, with a net present value (NPV) of $3,534,073.21 after one year. This research highlights the technical and economic advantages of hydraulic fracturing in maximizing well productivity. It provides a detailed recommendation for future stimulation activities in Well X, emphasizing the balance between production enhancement and cost efficiency.