Angola Block 3 is the offshore acreage covering an area of 4, 240km2, some 200km from Luanda, the capital of Angola. Water depths of the block are generally between 50 to 200m, reaching 400m. The block is underlain by the southern part of the Lower Congo Basin, which is a part of the West African Salt Basin Chain and characterized by the Aptian salt. Nineteen oil accumulations have been found mainly in the Albian carbonate and subordinately in the Turonian and Cenomanian sandstone, and seven of those are currently under production at total daily production of 180, 000 barrels from the Pinda carbonate. Data from the exploration activities indicate that the understanding of the reservoir distribution is key point for oil exploration of the Albian carbonate in the block. Lots of effort has been made to depict the reservoir distribution pattern of the Albian carbonate in the block by using the 3D seismic data. Intergrated interpretation of 3D seismic with well data and the geological model has led to the discovery of new oil accumulations.
Peciko gas field is located in offshore area, southern part of Mahakam delta system, East Kalimantan, Indonesia. Mahakam delta has been developed in the region since the Oligocene to recent, and it had been proved as petroliferous area by the discovery of giant oil and gas fields. In the early delineation stage of Peciko gas field, northward deviation of the gas zones was recognized by the drilling results, and stratigraphic trap of sand pinch out was considered as the trapping mechanism to explain this phenomenon. But the accumulation of the formation pressure data and knowledge from the sequence stratigraphic study suggest that the distribution of Peciko gas zones are not controlled by the distribution of the sandstone layers, but by a hydrodynamic trapping mechanism. This trapping mechanism is generated by the expulsion of compaction water in prodelta muddy facies in the east and south of Peciko gas field. The recognition of hydrodynamic trapping mechanism in the early stage of delineation was significantly helped the field appraisal. Discovery of Peciko gas field by new play type of hydrocarbon accumulation highly graded up the potentiality of Mahakam delta, and the hydrodynamic trapping mechanism can be applied in other fields.
The Vigdis field is located approximately 200km north-west of Bergen in Norway. The water depth ranges from 230m in the south to 300m in the north. The hydrocarbon is accumulated in a westerly tilted fault block in the Tampen Spur area, where numerous fields also have been discovered. The main reservoir rock in the field is the Middle Jurassic Brent Group deltaic sandstone. The Brent delta prograded from south to north with its thickness of around 200m in the field. The Brent Group is traditionally subdivided into five formations in this area from the youngest to oldest: Broom, Rannoch, Etive, Ness and Tarbert. Although each formation basically has a high sand/shale ratio, the lowest sand/shale ratio or relatively high shale content is observed in the Ness Formation which behave very important role in the fault seal in this field. The field, consisting of three structural elements, called Vigdis West, Vigdis Middle and Vigdis East is bounded to the east by a truncation of the Base Cretaceous Unconformity, to the north and west by OWC and bounded to the south by the E-W trending cross fault. The displacement of E-W trending cross faults is so small that the Brent Group is juxtaposed each other across the faults. Thus the faults might be considered to be non-sealing, which was a main exploration risk for Vigdis Middle. After drilling of exploration/delineation wells, the fault plane analysis along each boundary fault revealed that the Ness Formation, richest in shale content enhanced the sealing capacity of fault. The OWC in the field vary among the structural elements. It becomes shallower from Vigdis West to Vigdis Middle. The relative positions of the Ness Formation and other sandstone rich formations along the faults control the OWC discrepancies.
This paper discusses the methodology for fracture detection and fracture porosity evaluation through core description, mud log and well logs, using data from Yufutsu gas field, Hokkaido, Japan. The youngest fracture group observed on core (System C) consists mainly of open fractures and roughly correlates with the conductive type fracture image on FMI. The remaining core fracture groups (System A and B) are filled by minerals and correlate with the resistive type fracture image. These results suggest that a substantial part of fracture pore space is associated with System C. The drill stem test results show that the most reliable fracture indications on mud log and conventional well logs are lost circulation while drilling, spiky peak of showing and abnormaly low values of RLLD. The values of φFMI and φRLLD-RLLS are low and nearly equal because both are probably close to the minimum fracture porosity. The trend of SPI (φD-φS) is similar to those of φFMI and φRLLD-RLLS, but the values of the former are several times larger than those of the latter. As above mentioned, the value of fracture porosity is various due to the difference of estimation formula and quantitative fracture porosity evaluation of the study area is still on the trial and error stage. So, further study will be needed for establishing more reliable method of fracture porosity evaluation.
In the Minami Nagaoka gas field, north-northeast to south-southwest trending break-out dominate. The trend of maximum horizontal stress is vertically crossing the break-out that means west-northwest to east-southeast. The minimum horizontal stress value estimated from hydraulic fracturing method is slightly smaller than overburden pressure. The maximum horizontal stress is 1.58 times larger than the minimum horizontal stress. The Green Tuff in this field is expected to be in a strike-slip faulting regime, and the estimated differential stress at the depth of 4, 300m is about 490ksc. The Green Tuff exposed to tectonic stress largely exceeding the horizontal stress of a standard overburden pressure state. Therefore the dominant trend of opening fractures is assessed to be controlled by subsurface stress and to be parallel to the maximum horizontal stress. The results of triaxial compression test show that different lithofacies exhibit different stress-strain profile. This implies that the Green Tuff has the inner stress distribution controlled by lithological variation. Therefore, it is highly possible that the difference in deformation behavior, such as brittleness or ductility of the lithofacies in reservoir creates the environment in which remnant stress and local opening fractures are maintained in the Green Tuff reservoir. The combination of the regional tectonic stress and local stress distribution caused by lithofacies's variation is likely to control the distribution of opening fractures and therefore quality of the Green Tuff reservoir.
Hydrocarbon reservoirs in the Ayukawa oil and gas field are composed of middle Miocene argillaceous rock, acid tuff and dolerite. Various petrographic and petrophysical analyses of the dolerite reservoir suggest that it is formed by the selective dissolution of saponite which replaced mafic minerals and plagioclase during a duration of alteration. In the duration of alteration, three types of alteration facies in the dolerite and its surrounding rocks are distinguished; secondary mineral zoning characterized with abundant saponite, dissolution of saponite and plagioclase at low pH condition, and cementation by K-feldspar and/or dolomite. They are supposed to be analogous to a product by seawater dominated alteration (Mottl and Seyfried, 1983 and others) which occurs during cooling of dolerite intrusions. Similar types of alteration have been recognized in dolerites of other hydrocarbon fields in NE Japan as well, in which other dolerite reservoirs might be expected.
Recent developments of seismic exploration technology are reviewed in the Ayukawa area, Akita Prefecture, considered to be a typical ‘difficult terrain’ area for seismic exploration. Next, the areal distribution of dolerite facies in the Onnagawa Formation, a regional primary reservoir, is estimated through the following integrated approaches; (1) construction of a reliable amplitude anomaly map based on relative amplitude preservation, (2) extraction of the typical seismic characters obtained from well log data, (3) evaluation of seismic attribute displays, (4) inspection of seismic resolution by acoustic impedance modeling. By establishing a lithological evaluation methodology, it is possible to predict the distribution and thickness of dolerite facies in the Ayukawa area.
Since July 1994, Japan National Oil Corporation (JNOC) has been conducting a cooperative research project with UNOCAL Corporation, in order to develop and apply geophysical technologies for porosity and permeability predication in low-permeability carbonate reservoirs. For this purpose, many geological and geophysical data were acquired at the Southwest Andrews oilfield in Texas, U.S.A.. This paper briefly introduces the Carbonate Reservoir Characterization Project with Unocal, and shows some provisional results obtained from several field experiments such as 3-D seismic, P-wave and S-wave VSP, and crosswell reflection survey. Importance of the data integration for various data set having different nature and resolution will be also stressed in order to estimate the spatial distribution of reservoir properties away from wells.