A Decision-Oriented Techno-Economic Framework for Designing Fiscal Incentives in Horizontal Well Development of Marginal Oil Fields

Abstract

Horizontal wells are widely recognized for improving reservoir contact and recovery; however, their application in marginal oil fields remains economically challenging due to high capital intensity and fiscal exposure. This study develops a decision-oriented techno-economic framework to evaluate the feasibility of horizontal well development under Indonesia’s Production Sharing Contract (PSC) regimes, namely PSC Cost Recovery and PSC Gross Split. Using a representative Indonesian marginal oil field, production forecasting, cost modeling, and cash-flow simulations are performed to assess project viability under Pessimistic, Moderate, and Optimistic Scenarios. Economic indicators, including Internal Rate of Return (IRR), Net Present Value (NPV), Payout Time (POT), and Government Take, are evaluated, followed by sensitivity and optimization analyses. The analysis confirms that PSC Cost Recovery consistently yields superior economic performance compared to PSC Gross Split, particularly for capital-intensive developments. Optimization results indicate that Contractor Split adjustment and CAPEX Efficiency are the most influential fiscal levers, while Investment Credit and First Tranche Petroleum (FTP) adjustments have a limited impact. This study identifies the quantitative incentive thresholds required to achieve a contractor Minimum Attractive Rate of Return (MARR) of 15%, offering practical guidance for policymakers and operators in structuring fiscal incentives for marginal field development. The findings provide a structured basis for aligning horizontal well deployment with fiscal policy to sustain upstream investment.