Description: Accurate palaeoenvironmental analysis is at the heart of producing reliable interpretations and depositional models. This study demonstrates a multivariate statistical approach to facies analysis based on relationships between grain size and quantitative palynology. Our methodology has the advantage that it can be used on small amounts of sample, such as core or well cuttings, as the basis for facies analysis. Proof of concept studies involving the collection of grain-size and palynological datasets from well-exposed outcrops of the Middle Jurassic, Lajas Formation of the Neuquén Basin, Argentina, demonstrate that canonical correspondence analysis can be used to consistently recognize facies and aid in the determination of depositional environments. This study demonstrates the link between depositional facies, grain-size distribution, palynomorph hydrodynamics and assemblage taphonomy of palynomorphs. This knowledge can be transferred into a semi-automated statistical facies prediction technique for the subsurface in complex depositional settings, particularly when calibrated against conventional sedimentary facies analysis. Supplementary material: The full set of grain-size data and statistical scores are available at: https://doi.org/10.6084/m9.figshare.c.3745481.v1

Description: There is great potential for hydrocarbon exploration in the Triassic Baikouquan Formation, in the Mahu Depression of the Junggar Basin, NW China. Controversy remains around the conglomerate categories in coarse-grained deltas, which has inhibited further exploration in this area. Based on a dataset of cores, test data, well logs and seismic, this study attempts to recognize different genetic types of conglomerates formed within coarse-grained deltas. The Baikouquan Formation conglomerate has been divided into nine facies on the basis of textures, grain size and sedimentary structures. From the associations of these nine facies, three conglomerate categories have been recognized: debris-flow conglomerate (DFC); hyperconcentrated-flow conglomerate (HCFC); and traction-flow conglomerate (TFC). These have diagnostic characteristics that are expressed in core, well logs, seismic character, grain-size distribution curves and maximum particle size/bed thickness analysis (MPS/BTh). A depositional model has been built after analysis of the sediment transport mechanisms to facilitate exploration of the Baikouquan Formation, in the Mahu Depression. The evaluation of reservoir characteristics, physical properties and pore-throat structures of these conglomerate categories has identified the HCFC reservoirs as the primary potential targets for exploration in the study area.

Description: Regional seismic reflection profiles and well data from the Uruguayan margin were integrated in order to analyse and illustrate its tectonic and stratigraphic evolution. The evolution of the Punta del Este and Pelotas basins is divided into four major phases: pre-rift (Palaeozoic); rift (Jurassic–Early Cretaceous); transition (Barremian–Aptian) and post-rift (Aptian–Present). Each of these phases is characterized by a specific structural configuration and a stratigraphic architecture related to basin type, tectonic elements, sediment supply and base-level changes. During the geological evolution of the Uruguayan continental margin, a NE migration of depocentres occurred. The Cretaceous depocentre is located in the Punta del Este Basin, while the Cenozoic depocentre is located in the Pelotas Basin.

Description: The SH-1 wildcat well, firstly encountering oil, proved the existence of a working petroleum system in the Tenere Basin, but the origin of oil and its generation history is not fully understood. In this regard, one crude oil and nine Upper Cretaceous source rock samples from the SH-1 wildcat well in the Tenere Basin were characterized by a variety of biomarker parameters and stable carbon isotopic composition. The oil from the Tenere Basin displays a low pristine/phytane (Pr/Ph) ratio, low C 29 /C 30 and C 35 /C 34 hopane ratios, low C 22 /C 21 and high C 24 /C 23 tricyclic terpane ratios, and high gammacerane index (gammacerane/C 30 hopane), suggesting shale source rocks deposited under an anoxic and relatively high-salinity environment. Relatively high C 29 sterane concentrations, a low value of the regular steranes/17 α (H)-hopanes ratio and a canonical variable from stable carbon isotopic composition larger than 0.47 indicate that the oil is mainly derived from terrestrial higher plants. Both aromatic maturity parameters and sterane isomerization parameters suggest that the oil was generated from an early mature source rock. Correlation between oils from the Tenere Basin and those from the Termit Basin confirms that these oils belong to the same genetic family. The oil–source rock correlation suggests that the oil from the Tenere Basin originated from the Upper Cretaceous marine source rocks, and the Yogou Formation can be considered as effective source potential.

Description: The hydrocarbon source rock potential of shales from the Oligocene–Early Miocene Dingqinghu Formation was evaluated using organic geochemistry (Rock-Eval pyrolysis, total organic carbon (TOC) and bitumen extraction) and organic petrology. Forty-one outcrop samples from Lunbori and Jiangria Co shales in the Lunpola Basin were analysed. At Lunbori, in the central part of the basin, the shales have very good source rock potential, and show TOC contents ranging from 3.72 to 11.2 wt%, with an average TOC value of 7.36 wt%, S 2 values of 33.4 – 99.5 mg HC/g rock (average 61.8 mg HC/g rock), and extractable organic matter contents varying from 513 to 4525 ppm (average 2105 ppm). The shales have very good source rock potential. Rock-Eval T max values of 433 – 437°C (average 435°C) and high carbon preference index (CPI) values (4.76 – 6.70) indicate that the organic matter is immature to early mature for oil generation. The yellow fluorescence of kerogen under UV light is in good agreement with T max and CPI data. High hydrogen indices (HI) (635 – 1057 mg HC/g TOC) and H/C ratios (1.60 – 1.72) indicate that the Lunbori shales contain oil-prone organic matter and are characterized by high yellow fluorescing amorphous sapropelite content. The Lunbori shales contain a high content of hydrogen-rich Type II and minor Type I oil-prone kerogen, and have dominant medium to long molecular weight n -alkanes (maximizing at C 25 or C 27 ) with marked odd carbon number preference in the n -C 23 – n -C 31 range, pristine/phytane (Pr/Ph) ratios of 0.06 – 0.14, high phytane/ n -C 18 ratios (10.95 – 30.63), abundant gammacerane (gammacerane/C 31 hopane: 0.44 – 1.80), and predominant regular sterane C 27 . These data indicate deposition in stratified, anoxic and saline depositional conditions with a kerogen predominatly formed from a lacustrine biota. The Jiangria Co shales in the western part of the Lunpola Basin contain some hydrogen-rich Type I and II oil-prone kerogens at a marginally mature level. They have TOC contents of up to 2.62 wt%, S 2 values of up to 17.2 mg HC/g rock and extractable organic matter contents of up to 1731 ppm, indicating good source rock potential for oil generation. This is supported by their high HI values (420 – 720 mg HC/g TOC) and H/C ratios (1.05 – 1.50). The biomarker distributions of the extracts are characterized by odd carbon number predominance (C 23 –C 31 ), low Pr/Ph ratios (0.05 – 0.09), high concentrations of phytane and high gammacerane content, indicating lacustrine reducing and saline conditions.

Description: High-pressure methane sorption isotherms were performed on a series of Upper Ordovician Wufeng and Lower Silurian Longmaxi shale samples in the Fuling shale gas field to investigate the effects of organic matter content, thermal maturity, clay minerals, pore structure, temperature and pressure on methane sorption capacity. A large number of micropores with a pore width of less than 10 nm are developed within the organic matter, with its abundant specific surface areas as the fundamental factor to enhance the methane sorption capacity. The total organic carbon (TOC)-normalized sorption capacity increases with an increasing equivalent vitrinite reflectance R o , but an opposite trend is observed when R o is in the highly over-mature stage. The TOC-normalized sorption capacity shows no correlation with the total clay content as well as individual clay minerals. Most of the excess sorption capacity of shales increases with an increasing pressure, exhibits a maxima in the pressure range of 15–17 MPa and then decreases. The sorption isotherms show an obvious decrease in excess sorption capacity with increasing temperature. Moreover, the Langmuir pressure exponentially decreases with the reciprocal of temperature. Based on the Langmuir adsorption model, an empirical formula is established to evaluate the absolute sorption capacity of shales as a function of TOC content, pressure and temperature. Supplementary material: Additional description of experimental data are available at https://doi.org/10.6084/m9.figshare.c.3714040.v2

Description: An analysis of the characteristics of ultra-low-permeability reservoir rocks and the processes for permeability loss form the basis for establishing high-resolution well log interpretation models. Moreover, this type of analysis is a prerequisite for the effective development of ultra-low-permeability reservoirs. The Chang 7-1 sandstone members of the Triassic Yanchang Group in the Longdong region of the SW Ordos Basin are typical ultra-low-permeability reservoirs and are studied in detail in this paper. A comprehensive methodology of evaluating the ultra-low-permeability reservoir is developed based on geological information and well logging data. First, pore structure characteristics are analysed in depth using core observations, cast thin sections, scanning electron microscopy and mercury injection porosimetry. The mechanism behind the formation of ultra-low permeability in a reservoir rock, and its controlling factors, are also clearly determined. Second, from the above results and the pore structure characteristics in the study area, the flow-zone indicator (FZI) is selected as the key reservoir modelling parameter to establish permeability models that can reflect different pore structure types and improve precision compared to non-classification pore structure models. In addition, conductivity experiments with water-saturated cores confirm that the additional conduction phenomenon of clay minerals has little impact in terms of reducing reservoir resistivity and, consequently, the Archie formula is found to be reliable for ultra-low-permeability rocks with porosities greater than 5% in the Chang 7-1 reservoir. Three types of well log interpretation models, such as permeability, oil saturation and porosity, are established for the ultra-low-permeability reservoirs using FZI as a classifier in the research area. These models reduce the relative errors to less than 10% and performed well for the ultra-low-permeability Chang 7-1 sandstones. This study contributes to the evaluation of ultra-low-permeability reservoir rocks and also generates fit-for-purpose log evaluation models to guide completion interval selection.

Description: The kinetics of dolomite dissolution have been experimentally investigated under subsurface conditions characteristic of the Rotliegend gas fields in the NE of The Netherlands. Experiments were performed in closed, stirred, batch reactors at far from equilibrium conditions, with dolomite powders of different grain sizes. The experiments were repeated for all grain sizes at 25°C and an experiment was also conducted in deionized water. The rates were derived from the measured concentrations of Mg 2+ or Ca 2+ released from dolomite dissolution and were normalized by the surface area of the minerals at each time interval. Regression of the rates with the pH resulted in the kinetic rate constants of: log k 1 = –8.16 ± 0.06 at 25°C and log k 2 = –7.61 ± 0.05 at 100°C (300 – 350 μm), log k 3 = –7.88 ± 0.20 at 25°C, log k 4 = –7.45 at 100°C (75 – 100 μm), log k 5 = –6.62 ± 0.50 at 25°C and log k 6 = –5.96 ± 1 at 100°C (20 – 25 μm). The results obtained in this study indicate that in an acidic regime the dissolution of dolomite in brine is a factor of 2 faster than in deionized water. It was also shown that the dissolution rates, when normalized by surface area, increase with decreasing grain size.

Description: Total operated the Lacq CO 2 capture and storage demonstration pilot between January 2010 and March 2013. The injector well, RSE-1, was plugged and permanently abandoned in April and May 2015. As part of a risk assessment study, the hypothetical presence of micro-annuli in the outer cements of the well was studied, consisting of a 2.2 km-long pathway through two cement sheaths. A model was set up to couple the overlying Lasseube aquifer, the well cements and the Mano reservoir. The model concluded that no CO 2 can flow upwards into the Lasseube aquifer as the CO 2 storage reservoir is strongly depleted. The volumes of aquifer water that may flow downwards into the reservoir are very limited, with simulations suggesting rates of less than 0.01 m 3 /day. The cumulative volume of water that could flow down to the reservoir by the end of 2200 would be 0.0006% of the aquifer volume in the worse case. Both computed flow rates and volumetric hydrogeological consequences were therefore found to be of very small amplitude. This study concluded on the lack of risks related to a hypothetical loss of cement bonds with the shaly formations all along the cement sheaths of the 95/8 and 7 inch casings.

Description: In order to accurately model the subsurface of a new salt cavern gas storage facility at the Jemgum site in the Lower Saxony Basin (NW Germany), modern 3D pre-stack depth-migrated seismic data were utilized during an early planning stage. Gas storage projects are often regarded purely as engineering projects. However, the involvement of geoscientists provided an opportunity to further add operational value to the project by applying state-of-the-art geological modelling techniques. As part of the site characterization, a new generic workflow was developed to facilitate a more time-efficient creation of a static, multi- z -valued salt interface, essential for modelling of any complex salt structure. Uncertainties related to the reconstruction of salt interface meshes were analysed accordingly and used to quantitatively determine spatial uncertainties of the final static depth model. Furthermore, seismic-attribute images were created which enabled the detection of a mid-Miocene fluvial system evident at shallow depths of just 100–300 m below mean sea level. The study demonstrates that seismic data, targeting Rotliegend gas sands at depths of more than 4000 m, can be very beneficial to better understand the near-surface hydrogeological processes for gas storage.