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.

タイトレザバー開発を象徴する技術として，多段階水圧破砕と水平坑井掘削が挙げられる。タイトレザバーからの効率的な油ガス回収の達成には，水圧破砕による適切なフラクチャー形成が必要であり，水平坑井区間における岩石力学特性の把握が重要である。本検討では、比較的安価に実施可能でありカッティングス試料でも適用可能である蛍光 X 線分析（XRF）の活用を目指した。当社が坑井を保有する米国テキサス州のイーグルフォード層や秋田県の女川層では鉱物と岩石力学特性との間に相関が見られることから，元素データと岩石力学特性の相関が期待される。本検討ではイーグルフォード層の垂直パイロット井のコア試料にて XRF データと機械学習手法を用いた鉱物組成・TOC・岩石力学特性の推定モデㇽを構築し，同モデルを水平井のカッティングス試料のXRF データにも適用した。鉱物組成・ TOC 推定には重回帰ベースのモデルを作成し，両坑井においてシンプルなアルゴリズムから高い精度での推定に成功した。岩石力学特性の推定では重回帰・ランダムフォレスト・自動機械学習によりリーブ硬度を推定した結果，重回帰モデルと比較してランダムフォレストモデルや自動機械学習モデルではより正確な推定結果が得られた。また，これらの XRF 由来のリーブ硬度は垂直パイロット井の岩石力学モデルから推定した一軸圧縮強度と類似したトレンドを示した。その他にも、音波検層から得られた動的ヤング率・ポアソン比をランダムフォレストモデルや自動機械学習モデルから非常に高い精度で予想することに成功している。また、イーグルフォード層と同様のワークフローを女川層のコアサンプルに適用した結果、岩石力学特性の推定について良好な結果が得られた。本検討の貯留層性状評価手法はタイトレザバーにおいて汎用的な手法であることが期待される。

ナノ流体（NFs）は，前例のない多くの適用可能性を示す興味深い特性と顕著な特徴を備えており，特に石油業界では新しい石油増進回収（EOR）剤として可能性を示している。他の EOR 流体とは異なり，NFs に懸濁した固体粒子には，孔隙にトラップされた油を解放させる新しい回収メカニズムがある。本研究では，濡れ性と界面張力（IFT）を測定することにより，NFs 保持の影響と，さまざまな NFs 濃度でのコア掃攻実験を通じてその挙動を調査した。なお，本研究では，陽イオン性酸性シリカ - アルミナベースの NFs と合成油を使用した。濡れ性の測定は，シリカ-アルミナベースの NFs が岩石の表面をより水濡れ性に変える可能性があることを示した。一方，IFT 測定では， NFs は油と水のIFT 低減に顕著な影響を与えないことが示された。異なる NFs 濃度でのコア掃攻実験では，NFs 濃度 0.0025 wt .-％で最大 9 ％の追加油回収率をもたらすことが示唆された。また，NFs 濃度は，濡れ性や回収率に対して非線形の関係にあることも観察された。

中～後期中新世の珪質岩層は，日本の本州北西部を含む 北太平洋における石油探査の重要な対象と考えられている。本研究では，青森県南西部津軽盆地の DTH27-1号井で 採取された赤石層の珪藻質シルト岩と大童子層の珪質泥岩に関するデータを提示する。ロックエバル分析から得られた有機地球化学的データを用いて，青森西部における珪質泥岩の炭化水素ポテンシャルを評価した。全炭化水素量（S1＋S2），全有機炭素量（TOC），および有機物熱熟成度（T_max）の値は，珪質泥岩がこの地域の有望な根源岩であることを示している。しかしながら，青森県西部のこれらの地層は熟成度が低いことから，炭化水素は排出されなかったことを示している。この地域には生産性のよい根源岩層準は分布しないものの，津軽半島の大童子層と同年代の珪質泥岩は，青森県における石油探鉱の将来的な対象となる可能性がある。

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.