Since the two oil crises in the 1970s, E&P companies have been engaged in exploration and development with the belief that discovering and commercializing large reserves is a real charm of exploration and increasing production and reserves has been considered a mission for oil companies. On the other hand, oil price fluctuations and climate change countermeasures in the last three years have been changing more rapidly than ever before, and the movement toward energy transformation（EX）and social demand for decarbonization are becoming irreversible. Under these circumstances, what should oil companies aim for in their E&P business? First, an extreme energy conversion is not realistic, and a sustainable supply of oil and natural gas based on the premise of a thorough low carbonization is necessary for the "transition period" until clean alternative fuels are ready. Natural gas, in particular, will continue to be an important energy source during the transition period as an alternative fuel to coal or as a raw material for blue hydrogen and ammonia. A realistic roadmap for EX is needed, which includes making the project more resilient by promoting near-field exploration, fast track development and reducing E&P costs. It will also include making the business cleaner by performing CCS, electrification of plants and converting coal to natural gas to reduce GHG emission.

Considering the gradual transition from oil & gas to low-carbon or cleaner energy in the future, it is important to develop new technologies that have affinity with the core technologies of oil companies, such as monitoring CO₂ injection layer by using higher resolution 3D/4D seismic data. Furthermore, it is becoming increasingly important to have a sense of speed in exploration and development in order to avoid the projects from becoming stranded assets.

The Cenozoic rift basins in Southeast Asia have high petroleum potential and the petroleum system of each basin has been analyzed and characterized. Many studies revealed the presence of two types of source rocks （lacustrine shale and fluvio-deltaic coal）in the petroleum basins. In the Cenozoic basins in Southeast Asia, it has been recognized such a "dual petroleum systems" that the source rock distribution and kitchen area vary and the timing of oil and gas generation differ which make migration and accumulation processes more complex. Therefore, it is important to identify the effective source rock of oil and gas and well understand the petroleum system working in the area in exploration phase. Geochemical inversion utilizing biomarkers and isotopes is one of the commonly used methods to identify the effective source rock. Thermal maturity of each source rock and timing of oil and gas generation can be evaluated by basin modeling.

We performed geochemical inversion on fluid samples taken from reservoirs of a gas field associated with oil and condensate recently discovered offshore Vietnam. Two oil families（mixed oil derived from both lacustrine and fluvio- deltaic source rocks and purely fluvio-deltaic oil）were identified by biomarkers and diamondoids. Carbon isotope compositions suggested that gas generated from both lacustrine and fluvio-deltaic source rocks mixed in the reservoirs. Fluid inclusion analysis revealed the presence of paleo-oil column in a current gas-condensate reservoir which could be flushed by late-charged gas. Multi-dimensional basin modeling confirmed that mixing of different type of fluids during trapping and the possibility that oil initially charged into the field spilled-out to adjacent structures by late-charged gas after Pleistocene.

The well-understanding of this kind of complex dual petroleum systems will give us new insights on petroleum potential and useful information to develop exploration strategies targeting gaseous hydrocarbon in basins in Southeast Asia.

The results of pioneering carbon dioxide capture and storage（CCS）projects such as Sleipner and Gorgon are widely recognized as milestones in the early days of CCS. The reservoir formations of the pioneering projects are characterized by homogeneous sandstones that develop over several hundred meters thick. On the other hand, sandstone formations expected to work as reservoirs for CCS in Japan are characterized to be more heterogeneous and thinner than those of pioneering projects as above because of the tuffaceous sandstones typical of volcanic arcs. In addition, the geological formations in Japan that separated by complex faults in active continental margins might not be suitable for CCS reservoirs. However, we will have to make CCS feasible against these "challenging" formations. In this paper, examples of multidisciplinary approaches for geological evaluation of domestic depleted oil fields obtained from a joint study with INPEX are shared, and we hope that those findings would help future CCS projects in Japan.

In carbon dioxide capture and storage（CCS）projects, monitoring the plume and potential risks, for example, induced seismicity, is essential for safe and stable operation. Although the effectiveness of the monitoring technologies has been proven by existing pilot-scale projects, optimizing cost-benefit is necessary for large-scale CCS projects. However, there are many candidate methods and it is sometimes difficult to select an appropriate combination from them. Also, when grand design of the CCS project is not well recognized and the risk analysis is not implemented at the beginning, it often results in unnecessary confusion in planning the monitoring scheme. To tackle the challenges, visualizing the whole framework needed for monitoring design is proposed. We examined several published projects and extracted monitoring frameworks common to most of them. Also, the technology ranking method was reviewed for quantitative comparison of different monitoring methods. Based on these, we started our monitoring plan by teaming up with a variety of technical experts and listing up candidate monitoring technologies. We found that this approach was effective since we could build and share the concept of CCS monitoring through repeated discussions from the start. This made inter-technical cooperation possible, and the unbiased selection of monitoring technologies was achieved. We also started the process by assessing risk scenarios since we could understand from the extracted frameworks that a riskbased monitoring plan is essential for CCS projects. Understanding the whole framework enabled us to mitigate undesired confusion between each expert. We also discuss some of the newly recognized challenges in our monitoring design.

One of the key issues in gas production from methane hydrate-bearing reservoir is the excessive water production from adjacent aquifers and other sources. As a countermeasure, it is necessary to reduce the permeability of the surrounding aquifers to a distant extent. As a process of making this countermeasure possible, we are exploring the possibility of applying waterglass-based water blocking agent generally used in the construction industry. This paper presents the results of the experiment and numerical simulations and the direction of future studies.

In addition to an analytical result of two gas samples, published geological and geochemical data on the Isobe gas field, which had produced CO₂ commercially during about 30 years, are examined in this paper from the viewpoint of petroleum geology

Chemical and carbon isotopic compositions of gases from the field indicate that CO₂ is magmatic origin and has no relationship with hydrocarbons which are derived from the thermal decomposition of organic matters. Faults are ascending paths of CO₂, which is driving force for hot spring waters.

Chemical and isotopic compositions of associated waters with gases which are used as hot spring waters indicate that the waters are fossil sea waters which were entrapped during deposition and undergone diagenetic alteration. Higher temperatures of the waters estimated by the Mg-Li geothermometer than a bottom temperature at 1,500 m depth suggest that the waters are formed in deeper parts and derived from there.