Pumice rafts that arrived at the Nansei Islands, Japan, provided a unique opportunity to investigate the Fukutoku-Oka-no-Ba (FOB) eruption of August 2021. Despite drifting for two months for >1300 km, the drift pumice raft had a large volume and contained a variety of pumice clasts, some of which were deposited during a high tide in a typhoon, while others were washed up on a sandy beach. Most of the drift pumice clasts are gray in color, vesicular, and have a groundmass containing black enclaves, which are similar to those collected in the ocean near FOB about one week after the eruption. Rare black pumice and the main gray pumice components have similar trachytic compositions, with SiO2 = 61–62 mass% and total alkalis = 8.6–10 mass% (on an anhydrous basis). Both pumice types contain clinopyroxene, plagioclase, and rare olivine phenocrysts. Thin-section observations show that the gray pumice has more elongated vesicles as compared with the black pumice that has spherical vesicles, even where the two types of pumice are in the same clast. The glass in the black pumice is transparent and brown in color, while that in the gray pumice is colorless. No micro or nano-crystals were observed during electron and optical microscopy in the brown domain. Raman spectra of the brown-colored glass exhibit a clear magnetite peak, suggesting magnetite nanolites cause the brown color. High-Mg (100 × Mg/[Mg+Fe] = 92) olivine in the black pumice has an equilibrium temperature of 1240 °C and a rim diffusion profile indicative of re-equilibration with the surrounding melt over a period of hours to days.The textural relationships between the gray and black pumice suggest that the black pumice had become black and viscous before the two types of pumice mixed. Therefore, crystallization of magnetite nanolites and a corresponding increase in melt viscosity were important in the eruption preparation process, which then resulted in a large-scale Plinian eruption.

Faults and fractures were interpreted using attributes that were extracted from a 3-D seismic data set recorded over a Lower Cretaceous Thamama oil field in offshore Abu Dhabi, United Arab Emirates. The Thamama reservoir has good matrix porosity (frequently exceeding 20%), but poor permeability (averaging 15 mD). Because of the low permeability, faults and fractures play an important role in fluid movement in the reservoir. The combination of the similarity and dip attributes gave clear images of small-displacement fault geometry, and the orientation of subseismic faults and fractures. The study better defined faults and fractures and improved geomechanical interpretations, thus reducing the uncertainty in the preferred fluid-flow direction. Two fault systems were recognized: (1) the main NW-trending fault system with mapped fault-length often exceeding 5 km; and (2) a secondary NNE-trending system with shorter faults. The secondary system is parallel to the long axis of the elliptical domal structure of the field. Some of the main faults appear to be composed of en-echelon segments with displacement transfer between the overlapping normal faults (relay faults with relay ramps). The fault systems recognized from the seismic attributes were correlated with well data and core observations. About 13 percent of the fractures seen in cores are non-mineralized. The development of the fault systems was studied by means of clay modeling, computer simulation, and a regional tectonics review. The existing fluid-flow characteristics of individual faults and fractures in the field can be modeled using the present-day stress regime, with the maximum horizontal stress oriented north-northeast. Slip-tendency and dilation-tendency analyses simulating present-day regional stress conditions are indicators of fault and fracture transmissibility. The NNE-striking secondary fault system is parallel to the present-day maximum horizontal stress and could act as a flow conduit in the reservoir.

"A field" located in offshore Abu Dhabi has produced oil from the Jurassic carbonate reservoirs for 20 years under water injection scheme since 1997 after 10 years gas injection with maximum 20% water cut in some wells. The previous geological model was composed of box shaped fault pattern at down flank area derived from 2D seismic interpretation and mostly considered matrix reservoir properties with unsatisfied history matching quality, especially water cut behavior. In order to improve quality of static/dynamic models, geological model was mainly upgraded focusing on the following subjects:Fault re-interpretation was carried out with reference to analogy from adjacent oil fields, regional tectonic history and dynamic production performance. Radial fault pattern at crestal part in the domal structure was newly introduced.Since well test permeability was obviously greater than static permeability model derived from core plug measurements, fluid flow contribution by fractures was suspected. Hence, fracture density data from cores was reviewed and it is found that more fractures develop at selective layers and near the re-interpreted fault locations. Time-lapse water saturation data confirmed that water movement appeared at low matrix permeability intervals with higher fracture density. A conceptual fracture model was finally established based on the currently available data, and utilized to generate fracture permeability. These approaches provided multi realization results to assign higher permeability at specific layers and locations related to faults/fractures reconciling well test permeability, although uncertainties remain on the fault interpretation due to lack of 3D seismic data. It is very difficult to assess each realization and uncertainty including fracture permeability, therefore iterative loops between the geological model and reservoir simulator based on multi-realization models were required to generate a reasonably integrated permeability model. This collaborative process fully incorporating new geological model is in progress and the preliminary updated reservoir simulation using an essence of the conceptual fracture model suggested that matching quality was successfully improved compared with the previous model, particularly water cut behavior. Introduction "A field" located in offshore Abu Dhabi has produced oil from the Jurassic carbonate reservoirs for 20 years under crestal water injection scheme since 1997 after 10 years gas injection with maximum 20% water cut in some wells. The first water cut was confirmed in 2000 and the water production is gradually increasing. The previous geological model was composed of box shaped fault pattern at down flank area derived from 2D seismic interpretation and mostly considered matrix reservoir properties with unsatisfied history matching quality, especially water cut behavior (Fig. 1). In order to improve quality of static/dynamic models, geological model was mainly upgraded focusing on fault re-interpretation and integrated permeability modeling incorporating conceptual fracture model.

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