The incorporation of sulfur into kerogen in the early stage of diagenesis and the migration of silica during silica mineral transformation play important roles in the formation of Onnagawa siliceous source rocks. The S/C atomic ratio of Onnagawa kerogen is variable, affecting the timing of oil generation. Organic matter in the siliceous source rock is concentrated or diluted by the migration of dissolved silica accompanying silica mineral diagenesis, resulting in the formation of organic-rich and organic-poor siliceous rocks. Oil generation of Onnagawa siliceous source rocks rich in organic sulfur starts at low maturity level of vitrinite reflectance（VR）＝ 0.4 ％, that nearly corresponds to the transformation stage from Opal-CT to authigenic quartz. The volume reduction due to quartz crystallization leads to the effective porosity increase and fracture formation, resulting in the formation of siliceous reservoir rocks. Oil generation in the siliceous source rocks proceeds significantly at VR ＝ 0.4 to 0.6 ％, the similar timing of siliceous reservoir rock formation, leading to the formation of tight oil deposits consisting of low-mature oils（VR<0.6 ％）. Compaction and thermal maturation of siliceous rocks proceed further with increasing burial depth, inducing the oil expulsion. The oil expelled from the siliceous rocks at VR＝ 0.6 to 0.7％ has been accumulated to form conventional oil deposits in the Akita basin. Compared to the siliceous rocks and crude oils of Monterey Formation, those of Onnagawa Formation are characterized by lower organic sulfur concentration and smaller δ³⁴S value. Monterey siliceous source rocks significantly richer in organic sulfur were probably deposited in the super-reducing（euxinic）conditions. The diverse organic sulfur concentrations and oil generation kinetic parameters of Onnagawa siliceous source rocks are due to the diverse primary productivity and reducibility in the paleo-ocean of Onnagawa Formation.

Hydraulic fracturing（HF）is an essential technology in shale oil and gas development while how the fracture mechanism works and how much propagation occurs in-situ conditions are not clear yet, because the geometry of HF networks in shale formations becomes complex affected by its geological heterogeneities such as natural fractures and bedding planes. To understand the hydraulic fracture propagation mechanisms under in-situ conditions, JOGMEC conducted i）laboratory scale HF experiments with rectangular shale samples（65 mm × 65 mm × 130 mm）and ii） semi-field-scale HF experiments at an outcrop in the range of tens of meters. In this paper, we focus on the result of the semi-field test. JOGMEC conducted the preliminary HF test on the Unosaki coast of the Oga Peninsula, Akita Prefecture（northern Japan）in 2018 and 2019. The test results in 2018 indicate HF succeeded at dolomite concretion sections while a breakdown didn’t happen at the siliceous mudstone section. In 2019, JOGMEC decided to modify the HF test system including packer with shorter intervals, usage of high rate pumping, high viscosity fluid, and diverter to confirm whether a crack could form in the siliceous mudstone section or not. Calcite precipitation was observed on some siliceous mudstone samples from the success section through the result of QEMSCAN. Therefore, carbonate concentration could be an important factor for HF success while detailed analysis is required to select the target section before the HF experiment.

JOGMEC learned a lot from two years of semi-field scale HF experiments including know-how of both target selection and operation. It also has been recognized that the prediction of an adequate interval for hydraulic experiments is very difficult in the Onnagawa Formation due to its complex geological characteristics.

Development of tight reservoir is represented by multi-stage hydraulic fracturing and horizontal drilling. Optimized hydraulic fracturing design based on the geomechanical character of horizontal section is required in order to achieve efficient oil and gas recovery from tight reservoir. Generally, geomechanical analysis using core sample and sonic logging are helpful to capture a geomechanical feature, however, application of these technique is too costly way to obtain an enormous quantity of data from many producing wells. The use of X-ray fluorescence（XRF）-related techniques in shale plays has been standard method to evaluate rock character of fine-grained rocks due to the difficulties in visual characterization. For example, in the Eagle Ford play, there are many XRF-related studies, such as estimation of depositional environments, mineral composition, total organic carbon（TOC）, etc. In this study, we constructed the prediction model of mineral composition, TOC and geomechanical features using machine learning methods based on XRF data obtained from conventional core of a vertical pilot well in Eagle Ford. The constructed prediction model was then applied to the XRF data of horizontal well’s cuttings samples. Multi-regression, random forest and auto machine learning（Auto ML）were utilized to estimate mineral composition, TOC and geomechanical character in this study. Modified multi-regression model for estimation of mineral composition and TOC achieved similar quality with recent researches, and random forest and Auto ML model（tree algorism）were able to estimate Leeb hardness, Young’s modulus and Poisson’s ratio with high accuracy. As the workflow constructed with Eagle Ford sample worked well in Onnagawa Formation, this prediction techniques using machine learning methods is expected to be applicable for various tight reservoir plays.

Nanofluids（NFs）have interesting properties and distinctive features that present an unprecedented potential for many applications, especially in the petroleum industry, as the novel enhanced oil recovery（EOR）agent. Unlike any other EOR fluids, the solid-particles suspended in the NFs offer new recovery mechanisms to release the oil trapped in the pores. This research investigates the influences of NFs retention by measuring wettability and interfacial tension（IFT）and its behavior through core flooding with various NFs concentrations. In this research, cationic-acidic silica-alumina-based NFs and synthetic oil were used. The wettability measurements indicated that the silica-alumina-based NFs could alter the rock surface to be more water-wet. On the other hand, the IFT measurement showed the nanofluids did not have a pronounced influence on reducing the IFT between oil and water. The core flooding experiments with different NFs concentrations suggested that the NFs induced the highest incremental oil recovery factor of 9 % with 0.0025 wt.-% concentration. It was also observed that the various NFs concentrations have a non-linear relationship with the wettability and recovery factor.

Middle-late Miocene siliceous sedimentary formations are considered important targets for petroleum exploration in the North Pacific, including northwestern Honshu Island in Japan. In this study, we present data on the diatomaceous siltstones of the Akaishi Formation and the siliceous mudstones of the Odoji Formation from the DTH27-1 well in the Tsugaru Basin, southwestern Aomori Prefecture. Organic geochemical data from the Rock-Eval pyrolysis were used to evaluate the hydrocarbon potential of siliceous mudstones in western Aomori. S1+S2, TOC, and T_max data indicate that the siliceous mudstones are prospective source rocks in this region. However, the low maturity of these formations indicates that formations of western Aomori Prefecture could not expel hydrocarbons. Although in this area productive source rock horizons are not present, siliceous mudstones with the same age of the Odoji Formation in the Tsugaru Peninsula could represent future targets for the hydrocarbon exploration in the Aomori Prefecture.

The production of shale oil and gas from unconventional wells are typically declined within a short term. Each operator is trying to maintain production levels or prevent production levels from declining. Recently, applied nanotechnology is focused to increase the productivity of oil and gas and extensive research and development efforts are now common. Formulated fluids（nanoActiv^(r) Hydrocarbon Recovery Technology（HRT）, Nissan Chemical America Corporation, the United States）which are developed based on nanotechnologies are dispersion of unique surface modified nanosilica particles to enhance the stability in harsh reservoir conditions. Formulated fluids with nanoparticles contribute to increase the productivity of oil and gas for a long term due to penetration of highly stabilized nanosilica particles into the natural fractures and in the deep reservoir and peel off the oil droplet from the rock surface mechanically. In addition, Formulated fluids with nanoparticles works to modify wettability and reduce Interfacial Tension（IFT）, allowing more oil and gas to be mobilized in a re-pressurized environment created by using large volumes of injected fluid. Nano-sized particles penetrate further and more thoroughly permeate the natural fracture network than traditional remediation or stimulation technologies and resulting in longer and more complete production efficacy. We have obtained good results in oil and gas productivity from the majority of case studies in Permian basin.

In this paper, the technical challenges in enhanced oil recovery using a sodium silicate solution as a multi-purpose chemical are introduced to enhance oil recovery by alkaline flooding and prevent channeling flows through high permeability layer/regime and geological storage of carbon dioxide（CO₂）. We have focused on the sodium-metasilicate-hydrates（Na₂SiO₃.9H₂O; S-MS）from many types of chemicals. Firstly, oil properties with S-MS solution（pH12-13）are presented to carry out alkaline flooding based on measurement results of interfacial tension（IFT）, contact angle and emulsion formation with oil considering reservoir-water salinity. Secondary, in-situ gel formation using the reaction between S-MS solution and dissolved CO₂ is introduced as a blocking agent in high permeability flow-passes in an oil reservoir with different permeability layers. Both of Raman and SEM-EDS spectroscopy revealed that the formed gel is a sodium carbonate type gel（SC-gel）. Physical characteristics of SC-gel were investigated in respect of S-MS concentration, temperature and CO₂ gas pressure. The blocking effect was evaluated by threshold pressure gradient and gas permeability by forming in-situ SC-gel in a sandstone core. Then the core flooding test using heterogeneous core consists from two sandstones cores with different permeabilities was carried out to find improvements in oil recovery by alkaline flooding using S-MS solution and blocking effect by the in-situ gel formation with CO₂ gas injected. Furthermore, a new system（a kind of Carbon-dioxide capture, utilization and storage）using the S-MS solution is proposed for CO₂ capture, usage and geological storage into relatively shallow oil reservoirs or aquifers meet a safe and economical onshore CO₂ sequestration. Furthermore, it is also expected that the in-situ gel formation between S-MS solution and CO₂ gas emitted from fires of peat layer or coal seam has a possibility to extinguish large scale fires contributing global warming.

Traditionally, much effort has been made by means of “carbon capture and storage（CCS）” and “carbon capture utilization and storage（CCUS）” from the perspective of reducing CO₂ emission as an adaptation for climate change issues in the oil and gas upstream sector. The most typical CCUS in the sector is CO₂ enhanced oil recovery （EOR）. In addition to those efforts, according to a worldwide rise of more rapid response to the issues, the CO₂ emission reducing discussion is expanding to chemical EOR in the last few years. Since a short while ago before the expansion, a core discussion had grown by dealing with CO₂ emission in waterflooding operations because of recognizing higher CO₂ emission intensity due to energy consumption of water treatment, injection, transportation, and disposal. Polymer flooding as a typical chemical EOR can reduce and/or delay water production by improving sweep efficiency. This water reduction can contribute mitigating CO₂ emission. Therefore, this paper recaps state of the art discussion focusing on chemical EOR potentials in the context of reducing CO₂ emission.