Low oil price gives a negative impact to the capital investment in E&P activities, which could cause a steep oil price rebound in future. The price downturn decreases oil & gas asset value, consequently so China, India and other oil majors are accelerating many global asset deals through M&A. On the other hand, most Japanese companies cannot afford new investments, leading to diminishing international competitiveness, due to their difficult financial circumstances caused by long-term low oil price.

However, the current situation should be a golden opportunity for Japan to build up new assets under the Japanese flag and achieve earlier the goal of self-development rate of 40 % in 2030 as Japan's energy security target. Therefore, from the viewpoints of both of energy security and international competitiveness, Japanese government decided to amend JOGMEC Law to strengthen mainly JOGMEC's finance ability to push forward the private sectors' E&P activities.

JOGMEC's new functions enforced in November 2016 are as follows.

1. Financial support for M&A conducted by Japanese companies,

2. Adding equity support for the development stage after acquisition of interests,

3. Acquisition of NOC's shares that is difficult to implement by the private sectors,

4. Diversification of JOGMEC's fund-raising methods by debt financing with the government guarantee, and

5. Leasing of JOGMEC's geophysical survey vessel to the private sectors

Moreover, the government approved 500 billion JPY supplementary budget during 5-year concentrated investment term to support JOGMEC. At the same time, JOGMEC's project evaluation and risk management function was strengthened and several revisions were introduced to adequately implement the new law, such as intensive project screening, strict risk management procedure, strengthened corporate governance, and internal training and development of human capital.

The new JOGMEC Law was enacted to enhance Japan's energy security and international competitiveness, expecting JOGMEC to play crucial roles to attain these national goals by utilizing the new supporting tools actively and cooperating closely with private sectors.

In the development of reservoirs of natural gas dissolved in water and shale gas, knowledge of the adsorption behavior of natural gas on reservoir rock is crucial. Furthermore, it is reported that carbon dioxide, rather than methane, is selectively adsorbed on the clay minerals, which suggests a possible enhanced gas recovery by injection of carbon dioxide. This paper provides a technical discussion on the adsorption behavior of methane and carbon dioxide on mudstone samples.

The adsorption tests of methane showed that the amount of adsorbed gas increases with increasing clay mineral contents in mudstone. The adsorption test of carbon dioxide showed that the amount of carbon dioxide adsorbed is five times larger than that of methane. The amount of methane and carbon dioxide adsorbed to mudstone was well predicted by Langmuir's adsorption isotherm. The adsorption tests of a mixture of methane and carbon dioxide showed that the amount of adsorbed methane and carbon dioxide depends on the partial pressure of each gas. As the partial pressure of carbon dioxide increased, the concentration of carbon dioxide in the absorption phase increased and that of methane decreased. Meanwhile, the amount of absorbed methane and carbon dioxide was also observed to be affected by the gas phase composition. As the concentration of carbon dioxide in the gas phase increased, the amount of methane adsorbed increased to a value more than that obtained in the ideal state. When the concentration of carbon dioxide in the gas phase decreased, the amount of carbon dioxide adsorbed decreased greatly from the value obtained in the ideal state.

Injection of low salinity water yields incremental oil recovery (5-20%) with lower operation cost and less environmental load in comparison with other enhanced oil recovery (EOR) technologies. However, mechanisms how the decrease in salinity of injection water improves oil recovery are controversial because someone gets promising results, but another does not with their specific experimental setting (e.g., different rock and different crude oil). Recently, wettability alteration is supposed to play a key role for improving oil recovery by low salinity water. It is the process that salinity change affects wettability initially evolved in reservoirs by interaction among crude oil-brine (formation water)-minerals. Here in this review, core experiments for low salinity water injection are summarized to specify requirements that low salinity water has promising effects to improve oil recovery. Secondary, I analyze and summarize experiments and theoretical simulations that discuss interactions among crude oil, brine, and minerals depending on salinity (and pH). This aims at looking for a universal view for the interactions existing in reservoirs. Finally, it is demonstrated that the evolution of initial wettability in reservoirs can be divided into two processes; contact of crude oil to a mineral surface mediated by brine and adsorption of oil molecules on the mineral surface. These two processes are significantly related to the requirements of low salinity water injection. Besides, interactions significant in the two processes are specified; disjoining pressure (surface charges of crude oil and minerals) and molecular interactions (e.g., cation bridging, acid-base interactions), respectively. From the view point of crude oil-brine-mineral interaction, it is crucial to investigate oil-molecule-specific / ion-specific / mineral-specific surface charge and molecular interactions for elucidating mechanisms of enhanced oil recovery by low salinity water injection.

Five types of sulfate minerals, namely epsomite, metavoltine, sideronatrite, gypsum and jarosite were found on the core from the Ayukawa-Kita AK-1 well drilled in 1995. They were considered to be precipitated from the sulfuric acid formed by the oxidation of pyrite in the country rock. Their occurrence, powder X-ray diffraction pattern, chemical composition, solubility with water and hydrochloric acid are described in this paper. They should be easily identified as secondary products based on their occurrence, but some of them can be difficult to distinguish from some of the original rock-forming minerals by powder X-ray diffraction patterns, because of their similarities in the patterns. Therefore, it might be necessary to be familiar with secondary products of core samples for analysts. Furthermore, the first thing we have to do is to analyze and grasp the important information of core immediately after the sampling of core before they deteriorate.