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Interest in CCS project development is accelerating in SE Asia, driven by the need to monetize emission-intensive assets in the region while complying with increasingly ambitious GHG emissions targets. Depleted hydrocarbon fields represent an attractive storage option for early CCS project due the enhanced understanding of the reservoir, its dynamic behavior, and proven storage capability. Re-use of existing infrastructure also presents the potential to reduce both project costs and time to first injection, however, these brownfield sites also carry significant risk to the long-term, safe containment of injected CO2 through risk of leakage via legacy wells. A methodology is presented in this paper to investigate the risk-reward balance of developing a depleted gas field as a storage site in the Gulf of Thailand. A screening process to assess all abandoned, suspended, and active wells is used to identify wells with re-use potential as CO2 injectors or CO2 plume monitoring wells, and those which represent a leakage risk to the project. A set of legacy well risk identifiers is generated for the field based on well construction records, descriptions of current well barriers, well utilization history, and current best practice guidelines. Southeast Asia has significant remaining reserves of oil and gas, and coal, and an active liquefied natural gas (LNG) export industry. The region's energy demand is increasing rapidly and is forecast to continue to grow over the next decades (World Economic Forum, 2019). To date, fossil fuels have supplied nearly 90% of this growth in the demand for energy in the region (IEA, 2021). To meet this growing energy demand, several new gas projects are under development across Southeast Asia, but many of these are associated with high CO2 gas fields where the produced gas contains significant (up to 70% by volume) CO2 (GCCSI, 2020). In Thailand, where nearly 94% of the primary energy is met by fossil fuels (BP Statistical Review, 2022), the energy sector represents the biggest contributor (74% in 2013) to the country's greenhouse gas emissions (GHG; UNFCCC, 2020). However, as per the nationally determined contribution to the United Nations Framework Convention on Climate Change (UNFCCC), Thailand intends to reduce its GHG emissions by at least 20% from projected business as usual levels by the year 2030 (UNFCCC, 2020). Carbon capture and storage (CCS) represents one option to help meet this increased demand in fossil energy while also reducing GHG emissions. An approach which is gaining traction across the region is to utilize the high concentrations of CO2 stripped out of the raw gas streams at gas processing plants and, instead of venting to atmosphere, the CO2 can be compressed, dehydrated, and transported to suitable long-term storage locations. Depleted oil and gas fields form an attractive opportunity for long-term storage of CO2 due to the wealth of both static and dynamic knowledge available from appraisal through production activities. Depleted fields also have the advantage that they have a working primary seal for hydrocarbons, which has been proven over geological time and so can be considered, in general, to carry low risk of leakage through geological means. Brownfield sites can, however, also represent a challenge to project success through an increased risk to the containment of the injected CO2 due to the presence of legacy wells. These existing wells represent a variable risk to containment depending on well age and type, well history, well design, and plug and abandonment methodology applied. This paper presents the outcomes of a CO2 storage feasibility study for a depleted gas-condensate field in the Gulf of Thailand. The main aims of the study were to:1) identify the project risk associated with the integrity of the field legacy wells, and 2) to evaluate the potential for well re-use for the CO2 injection project. Reusing an existing field offers new life to an otherwise end-of-life asset, inching towards decommissioning and site closure. As commercial scale CO2 storage in depleted hydrocarbon fields represents a ‘First of a Kind’ project, the feasibility study is designed to evaluate the current status of the field and surface facilities with respect to CO2 injection and long-term storage. As a feasibility study, the focus of the technical work was to identify any ‘showstoppers’ which might indicate that the selected site was not suitable for long-term CO2 storage and, if sufficient positive storage indicators were identified, to select the most appropriate options for progression into a Concept Selection study in which more detailed engineering studies will be completed.

Abstract Underneath the ground, the world still left a quarter of its natural gas resources (approximately 2 billion TCF) undeveloped or "Stranded" in offshore. Many gas fields were discovered in many decades ago, but the resources of those fields could not commercially be justified for the development so they were classified as marginal fields. One of the most promising solutions known as "Floating Liquefied Natural Gas or FLNG" is lately growing and foreseen as potential technical to monetize these marginal gas fields offshore and near-shore. We are well aware of the potential in FLNG technology and consider it as the one of the most important initiatives to lead our organization to achieve target growth. Many challenges in developing FLNG, however, have been found from major players in the past decade. Although land-based LNG and offshore FPSOs are each successfully proven in operations, combining the two technologies into FLNG is complicated and face various technical challenges e.g. safety, ship motion, topside processing, hull & containment, offloading, integration, and operation. The critical aspect of FLNG is space constraint, which requires fully attention in order to deliver inherently safe and fit-for-purpose installation. Altogether, FLNG concept shall fulfill a good balance between efficiency and simplicity to safeguard the reliability of the facility. Moreover, commercial aspect of FLNG is also highly challenging. With costly investment, FLNG project shall be carefully ensured if it is economic viable in every step of the project. The sensitivity of market, LNG price, and demand & supply shall be reviewed and taken into consideration prior to making the Final Investment Decision (FID). Certainly, FLNG initiative still has a lot of queries. However, after years of study and development in all aspects of floating liquefaction, it finally leads to the key conclusion that today there is no technical issue as "show stopper" for FLNG; whereas economic is also promisingly attractive. We believe that we have started on the right track and in the right sequence as well as adopting a risk management in selecting the right size and the right technology for FLNG.