Widodo Wahyu Purwanto

The injection stage of the CO ₂ storage process presents distinct technical challenges, primarily in managing multiphase flow dynamics. A comprehensive understanding of phase behavior and P – T effects is required to support efficient injection and optimal storage capacity. In this study, to maximize storage capacity, multiphase CO ₂ injections were simulated in a low‐pressure depleted gas reservoir in the Musi Field of South Sumatra. The economic analysis evaluates two business models (storage‐as‐a‐service and carbon‐credit storage service), each assessed within three cooperation schemes (gross split, cost recovery, and public–private partnership), using key financial indicators including NPV, IRR, contractor and government take, and the cost of CO ₂ storage. The simulation results indicate that CO ₂ storage in depleted gas reservoirs can be optimized through a variable‐phase injection approach. Injection begins in the gas phase while the reservoir pressure remains low until it reaches the CO ₂ bubble point. Subsequently, operators would inject dense‐phase CO ₂ as the reservoir pressure increases. The injection strategy evaluates multiple wellhead pressure settings and identifies a pressure‐profile discontinuity characterized by a sudden increase in bottom‐hole pressure when the wellbore pressure crosses the CO ₂ gas–liquid saturation boundary. With this variable‐phase injection management scenario, CO ₂ storage of up to 67.4 million tons can be achieved in 33.4 years. The storage fees for PPP, cost recovery, and gross split schemes are $11.94, $12.58, and $14.32 per ton CO ₂ , respectively. Carbon credit services follow suit with fees of $36.16, $35.82, and $43.39 per ton CO ₂ under the same schemes.

Minimizing supply chain costs is a critical challenge for the successful deployment of full-chain CO₂ capture and storage (CCS) systems, particularly in industrial clusters with diverse source and sink characteristics. This study presents a superstructure optimization model using Mixed-Integer Linear Programming (MILP), focusing on a case study in South Sumatra, Indonesia. The model’s key innovation is the integration of time-dependent reservoir injectivity profiles, derived from well simulations and decline analysis, directly into the MILP framework. This allows the model to constrain injection timing and capacity, accurately reflecting reservoir availability over a 30-year planning horizon. The model evaluates multiple network configurations, including single-well and multi-well systems, allowing for coordinated injection scheduling. The results highlight the critical role of Hub-based infrastructure, where optimized configurations reduce transportation costs by approximately 34%, from an average of $25.36 to $16.72 per ton, through economies of scale and shared infrastructure. Multi-well systems further improve storage capacity and injection efficiency, particularly when injection schedules are carefully optimized. By strategically managing injection capacity and scheduling reservoir availability, the system achieves additional cost reductions, with transportation costs ranging from $15.89 to $16.56 per ton. The findings highlight the critical role of superstructure-based designs in optimizing the interactions among sources, sinks, and transportation networks. Coordinated injection strategies and infrastructure planning are essential to reducing CCS costs and enhancing scalability. This study underscores the value of systematic optimization in achieving cost-effective and scalable carbon storage solutions across diverse industrial contexts.

The government of Indonesia has launched programs to decarbonize its power systems by replacing fossil fuel-based plants with renewable energy. Solar photovoltaic (PV) deployment faces economic and technical barriers despite abundant solar irradiance. This study evaluates techno-economic strategies for 10 MW grid-connected solar PV systems, comparing two scenarios: without Battery Energy Storage System (BESS) and with BESS to reduce grid reliance. Key interventions were analyzed for their economic impacts, including tariff adjustments, carbon tax implementation, and competitive auction schemes. The results show that without BESS, the project achieves an Internal Rate of Return (IRR) of 21.30%, making it highly feasible. However, including BESS lowers the IRR to 5.89% due to higher costs. Combining carbon tax and tariff adjustments improves feasibility, achieving a Profitability Index (PI) of 1.00 and an IRR of 14.74%. Competitive auctions further lower costs, enhancing the feasibility of BESS projects. While solar PV without BESS is economically viable, risks of capital cost increases require attention. For BESS projects, policy interventions such as auctions and incentives are essential. This study highlights strategic measures to accelerate solar PV adoption in Indonesia, providing insights for policymakers and investors to scale up renewable energy deployment effectively.

This study proposes a conceptual design of green hydrogen production via proton exchange membrane electrolysis powered by a floating solar photovoltaic system. The system contributes to industrial decarbonization in which hydrogen blending with natural gas is proposed as an approach to smooth the energy transition. The proposed design addresses the challenge of supplying a continuous flow-rate of green hydrogen, which is typically demanded by industrial end users. This study particularly considers a realistic area required for the installation of a floating solar photovoltaic system. To enable the green hydrogen production of 7.5 million standard cubic feet per day, the required structure includes the floating solar photovoltaic system and Li-ion batteries with the nominal capacities of 518.4 megawatts and 780.8 megawatt-hours. This is equivalent to the requirement for 1 524 765 photovoltaic modules and 3718 Li-ion batteries. The assessment confirms the technical viability of the proposed concept of green hydrogen production, transportation and blending. While the present commercialization is hindered by economics due to a high green hydrogen production cost of USD 26.95 per kg, this green hydrogen pathway is expected to be competitive with grey hydrogen produced via coal gasification and via natural gas steam reforming by 2043 and 2047, respectively.

This study assesses Jawa-Sumatera interregional electricity system’s long-term planning until 2050. The planning is determined based on least-cost optimization in the TIMES model. The model considers a high disparity between regions such as electricity demand, power generation infrastructure, and energy resources. There are twenty-seven technology power generations and three energy storage technologies competing in this model, the modeling also reviews the pattern of generating operations and the role of energy storage on an hourly for each region. A trading scenario was applied to plan power generation with interconnected transmission between Jawa-Sumatera by HVDC transmission. The results show power generation portfolio for BAU and the trading scenario in Jawa and Sumatra is dominated by a gas-based power plant. The trading scenario results in an increase of 70% installed capacity in Sumatera and a decrease of 23% installed capacity in Jawa, an average of 1.96 TWh of electricity is exported every hour to Jawa, a decrease in electricity production cost for Jawa from 10.69 cUSD/ kWh to 9.15 cUSD/kWh and Sumatera from 6.77 cUSD/kWh to 4.88 cUSD/kWh, an increase in renewable energy penetration especially utility-scale PV in Sumatera 19% and a reduction in emissions to 322 gCO2/kWh and required transmission capacity 43.6 GW in 2050 to distribute electricity from Sumatera to Jawa.