Corrosion Resistance of Well Steel in a Supercritical Carbon Dioxide Environment in Geothermal Systems Utilizing Depleted Hydrocarbon Reservoirs

This study evaluates the corrosion behavior of N80 production tubing steel under high-temperature, high-pressure (HTHP) conditions representative of CO2-based geothermal exploitation in depleted hydrocarbon reservoirs. We developed a staged laboratory protocol that simulates (i) an early multiphase production window (oil + formation brine + supercritical CO2), (ii) the same environment with the originally developed non-commercial inhibitor (INH), and (iii) a later stabilized stage dominated by near-anhydrous supercritical CO2 (scCO2) with trace brine and oil. Corrosion was quantified by gravimetric mass-loss, complemented by multi-scale surface characterization (2D/3D optical profilometry) and microscopic cross-section analysis. In the early multiphase scenario unprotected N80 experienced severe attack (mass-loss rate ≈ 0.67 mm·year−1) with both uniform corrosion and incipient pitting beneath ferrous-carbonate deposits. Addition of an inhibitor at 5000 ppmv reduced mass loss by more than an order of magnitude (to ≈0.09 mm·year−1, ≈97% inhibition) and substantially limited pitting. Under stabilized, near-dry scCO2 conditions, corrosion was negligible (≈0.0016 mm·year−1). Multi-scale imaging linked observed morphologies (porous FeCO3 scales, under-deposit pits) to measured rates and supported stage-specific mitigation recommendations. The novelty of this work lies in the integrated, staged HTHP experimental approach and in providing quantitative, actionable inputs for material selection, inhibitor deployment, and monitoring strategies for CCS–EGS projects that reuse depleted hydrocarbon reservoirs.