The depositional environment of the Kazusa Group Plio-Pleistocene epoch in the southeastern part of Kanto Plain is discussed, based on chemical and mineralogical analyses of 51 mudstone samples taken from Ichihara, Kami-ota and Oami bore holes.
Total sulfur, form of sulfur compound such as monosulfide, disulfide and sulfate sulfur, organic carbon, and total nitrogen are analyzed for the above samples.
The authors discriminate two kinds of fromboidal pyrite, namely, the pyrite filling the foraminiferal cells and that covering the cells. The former type is found in the upper horizons such as the Kakinokidai, Chonan, and Kasamori Formations, and the latter one occurs in the lower horizons as the Kiwada, Otadai and Umegase Formations. The former one might be formed under the aerobic condition in the depositional area, and the anaerobic condition prepared locally in the cells of foraminifers due to the decomposition of organic matter. On the other hand, the latter one is formed under the anaerobic condition due to the higher rate of deposition and the closed circumstance of the basin.
The ratio of pyrite in sulfur compound is lower in the samples of bore holes compared with that taken from the outcrops. This is due to the oxigenic condition near the surface of the earth.
The ratio of total carbon to total nitrogen reflects the contribution of higer plants to plankton in the sea. It is higher in the lower part of Umegase Formation, the Otadai and the Kiwada Formations. This might be due to the narrow basin at those stages.

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A procedure for the numerical simulation of a two-dimensional, single phase geothermal hot water convection system was developed. Galerkin's finite element method with triangular elements was applied. The procedure was implemented by FORTRAN and was verified by execution tests. The program was applied to simulation of the natural evolution of a geothermal system to its final steady state. The procedure is based on general conservation equations having accumulation terms, and thus can avoid troubles on convergence which might occur in case the steady state is postulated in the program. The procedure may be applied to the development of simulators effectively used for understanding the physical processes in liouid dominated hvdrothermal systems.

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The Shahejie Third Member (E_s3) was deposited in the most part of Gulf of Bohai during early Oligocene in age.
In this paper, we discussed the relation between the sedimentary environments and the reservoir qualities of the E_s3 sandstones concentrated on BZ 34 area.
The Esa sandstones are interpreted as deposits under the wave dominated delta environment which is divided into four facies, such as (1) open lacustrine, (2) sand flat/distributary mouthbar, (3) lagoon/bay/washover and (4) distributary channel/crevasse/overbank swamp, from the results of facies analyses with cores and wireline log date. It is considered that there have been five delta cycles which prograded northeastward or northward during early Oligocene.
On the other hand, it is suggested that the most important factor to control the reservoir qualities of E_s3 sandstones is grain size which is related to the sedimentary facies. From these discussions, we concluded that sandstones with large grain size have the best reservoir qualities in the Shahejie Third Member of this area. These sandstones were deposited under distributary channel, sand flat and distributary mouthbar environments.

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Since June 1980, the Egyptian Petoroleum Development Co., LTD. (EPEDECO) started oil production from sandstone reservoirs in Miocene Rudeis formation at H and K Oil Fields in West Bakr area, Eastern Desert, EGYPT. The cumulative production volume at the end of 1987 was 11.5 millon barrels.
Following the production, water cut incerease started from wells located at the flank of K structure, due to strong water drive. Chemical analysis data of waters in the K Oil Field shows a tendency to preserve high salinity around the crest of structure and decrease salinity toward the flank of structure. Vertical salinity change in a thick sandstone reservoir was confirmed by continuous water analysis, correlation of SP curves and the salinity change before and after set bridge-plug at K-5 and K-8 wells. That is to say, the high salinity water above oil water contact (OWC) is connate water, while low one below OWC is aquifer water effected by meteoric water.
In H Oil Field, the reservoir shows variety of thikness, ranging from 45m at H-3 to Om at H-4. For the purpose of clarifing sand-body distribution and the initial recoverable oil inplace, sedimentary facies of the reservoir were studied based on core observations, lithology classification by EC Logs and dip-meter data from wells in this field. As a result of study, the sandstone reservoir is possiblly of a deep-sea fan deposite with E-W axis.

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The authors describe the outline of stratigraphy, geological structure and characteristics of hydrocarbon accumulations in the Northern Oman including Japex Oman Ltd's., contract area.
The sedimentary sequence in the Northern desert of Sultanate of Oman ranges from the Proterozoic through Mesozoic to Tertiary, and seems to be extended from Abu Dhabi and Dubai regions. Eleven named groups are recognized: in stratigraphic ascending order, Huqf (Pre-cambrian), Haima (Lower Paleozoic), Misfar (Devonian), Haushi and Akhdar (Carboniferous to Triassic), Sahtan (Jurassic), Kahmah (Lower Cretaceous), Wasia (“Middle Cretaceous”), Aruma (Upper Cretaceous), Hadhramaut (Paleogene) to Fars (Neogene). The basement has not been tapped by wells yet in the northern part of Oman.
In the Northern Oman, four tectonic provinces are presently established as Suneinah Trough, Front of Hawasina Nappe, Fahud Salt Basin and Lekhwair High.
Hydrocarbon accumulations have been recognized currently in the Lower and Middle Cretaceous, however, the economic quantities of oils are found in the Garboniferous, Permian and Jurassic recently, in the Northern Oman.

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An eight-years exploration effort since 1980 on Block 3 in Angolan waters has resulted in twelve oil discoveries in the Albian Pinda carbonate among twenty-four explora-tion wells. This high rate of success is attributed to favorable setting of source rocks and reservoir rocks both of the Upper Cretaceous age.
Reservoir properties of the Pinda carbonate are strongly influenced by a combination of sedimentary fabric and subsequent diagenesis. The repeated sequence of deposits on highenergy oolitic shoals and interupting emergence upgrade the reservoir quality. On the other hand anhydritization, a long-lived diagenesis, controls the final reservoir quality according to the degree of its effect.

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The Tano, Central and Keta basins, distributed offshore Ghana from west to east, have been developed as pull-apart basins since the Mesozoic era. These basins are located to the east of the St. Paul and Romanche fracture zones, and they are thus interpreted to have been affected by strike-slip movements. Detailed seismic interpretation of the Central basin, where approximately 4, 500km of seismic survey was conducted by JNOC in 1987, indicates that structural configuration of the survey area has been formed basically under ENE-WSW trending right-lateral shears and has been locally modified in relation to sedimentation or existing faults.
The structural configuration of the survey area is characterized by faults, folds and uncon-formities, which also contribute to the formation of traps for hydrocarbon. Numerous pros-pects are delineated in the survey area, and they consist of both undrilled closed structures similar to the Saltpond oil field structure and closed structures of various trap types in the poorly explored Cretaceous strata which have source and reservoir rock potential. The Central basin is, therefore, interpreted to be prospective and should be further explored.

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