In this paper, application of simulation techniques for the evaluation of a steam flood pilot test is described. The pilot test has been conducted with a single inverted five spot pattern in a heavy oil reservoir. Thermal reservoir simulators generally take more calculation time than isothermal ones because both energy balance equations and material balance equations have to be solved; small time step sizers are required to establish numerical stability due to steep reduction in heavy oil viscosity with temperature increment. Thus, most of the application of the simulation to real field has been aimed at such a limited area as 1/8 symmetric element of a whole flood pattern. In the previous issue, the process and the results of simulation study using 1/8 symmetric model was presented. The results were examined and proved to be basically reasonable in comparison with actual reservoir performance observed by several monitoring methods. In this paper, a full pattern model including all pattern wells is constructed. History match for about two years of steamflood performance is done where some knowledge obtained in the previous issue is utilized. Furthermore, influence of fluid conductivity across a fault suggested in a geological study of the field is investigated with the model. At last, the importance of reservoir monitoring, for instance, bottomhole temperature survey, for the restriction of degree of freedom of the full pattern model, is discussed.
Carbon and hydrogen isotope analyses of 25 crude oils from Northeast Japan have been performed on total oils, saturates, and aromatics. Carbon and hydrogen isotopic compositions of total oils and saturates become heavier with increasing maturity. This relationship between isotopes and maturity of crude oils can be explained by kinetic isotope effects of oil to gas cracking. During oil to gas cracking, excess hydrogen should be required in response to high H/C ratio of generated gas. In the case of oil to gas cracking in reservoirs, all the excess hydrogen required must be generated from within the oil, while in source rocks extra hydrogen could be derived from aromatization reactions within the source kerogen. This difference should change the carbon and hydrogen isotope distributions in crude oils. Gross compositions indicate 2 condensate samples are experienced maturation process in reservoirs and the other samples are matured in source rocks. Two condensate samples showed relatively light isotopic compostions in aromatics. This is probably due to aromatization reactions within the reservoirs. The difference of isotopic distributions of total oils and aromatics between carbon and hydrogen in crude oils supposed to be matured in source rocks indicates excess hydrogen was derived from kerogen.
Light hydrocarbon compositions of petroleums are genetically informative. They reflect nature and maturity of original materials under the influence of secondary processes such as migration and transformation within reservoirs. The three indices based on light hydrocarbon compositions, proposed by Hiratsuka (1976) are very useful for classification of oils and condensates in the oil-field region of northeast Honshu, whereas the criteria by Thompson (1981) is not applicable to it. The hydrocorrosion index is the ratio of 2, 3 dimethylpentane to n-heptane and shows a degree of hydrocorrosion including water washing and biodegradation. Hydrocorrosion appears to have no effect on two other indices in the oils and condensates when a hydrocorrosion index is less than 0.25. Two other indices include the ratio of n-heptane to 1 trans 3 dimethylcyclopentane and the ratio of toluene to methylcyclohexane, termed as evolution index and environment index, respectively. From a crossplot of both parameters, the oils and condensates can be valuably classified and two types of condensate, which are due to phase redistribution and maturation, are differentiated. Comparision of evolution index with carbon isotopic composition and biomarker composition of the same oil or condensate suggests that evolution index is a reliable maturity index.
Coal pyrolysis test of vitrinite and sporinite has revealed that vitrinite reflectance (Sekiguchi and Hirai. 1981) and sporinite fluorescence maximum (Ting and Lo, 1975) exponentially increases with increasing temperature. While, it has been reported that the increase of vitrinite reflectance during hydrogenation was much smaller than that of coal pyrolysis and that vitrinite reflectance is greately suppressed in vitrinite macerals associated with hydrogen-rich kerogen (Price and Barker. 1985 and others). Fujii et al. (1982; 1988) reported that vitrinite reflectance is decreased with increase in the hydrogen-rich degradinite percentage and that sporinite fluorescence maximum is increased with increase in the hydrogen-rich degradinite percentage. During coal hydrogenation stage or oil generation stage, in vitrinite macerals, vitrinite reflectance suppression is caused by an incorporation of certain amounts of hydrogen into vitrinite macerals through dehydration of hydrogen-rich degradinite and sporinite. On the other hand, in sporinite, chemical dehydration by loss of hydroxyl groups and increase in aromatic nature leads to longer wavelength of sporinite fluorescence maximum.
The detailed investigation of the vertical variation of the hydrocarbon property in the Umm Al-Anbar (AR) field reveals that the top of the oil reservoir is sealed by a 30 feet thick anhydrite bed, but the volatile oil reservoir which is distributed below the black oil reservoir is clearly separated by an 8 feet thick anhydrite bed. The geochemical analyses of the samples from the studied area suggest that this oil and the volatile oil have not been generated from different source rocks but from the same source rock. Moreover, the paleostructure of the bitumen zone in the AR field shows that the oil was accumulated before Halul time. Also the saturation pressure of volatile oil reservoir calculated from the experimental data indicates that the gas migration was completed in Rus time. These facts will imply that the oil and gas migrated vertically and individually, which means that the oil migrated prior to the gas migration, and that the distrbution of the hydrocarbons was controlled by different seal potentials of anhydrite beds and clayey lime-mudstone at each migration time in proportion to the progress of the diagenesis. On the basis of the above assumption, the oil and gas migration in the structure is well-explained as follows: Firstly, oil migrated to the Arab reservoir from the Diyab Formation and accumulated in the crest before Halul time, when only more than 30 feet thick anhydrite bed could be affected as seal bed for the oil. Secondly, the gas migrated to the oil reservoir and changed this oil into the volatile oil. However, this gas migration was limited by the 8 feet thick anhydrite bed and the oil reservoir above the 8 feet thick anhydrite bed remained as oil reservoir itself.
In the present paper, the algorithm for automatic picking of seismic reflection on seismograms is proposed. The procedure of proposed algorithm is as follows. 1. The seismograms are transformed to the maximum amplitude seismograms which contain the amplitudes on both all peaks and all troughs. 2. The time to start the picking of reflection is assigned on each trace in the maximum amplitude seismograms. 3. A lateral continuity search between the traces on seismograms is carried out by use of amplitude ratio, cross-correlation coefficients and semblance across the traces in order to define reflection segments. 4. Each segment is classified into grades according to magnitude of amplitude and length of segment. 5. If necessary, after some kinds of scaling are applied to all segments for decreasing the segments to be plotted, the segments are displayed to make cross-section. Judging from the results in model studies of the synthetic seismograms and the output from velocity analysis in which this algorithm was applied, it was concluded that the picking of seismic reflection on seismograms was carried out with enough accuracy.
The first field test by a new PDC core bit with 815/32 in. outside diameter in a geothermal well called HDR-2, drilled at Hot Dry Rock project site in Yamagata prefecture, resulted in granodiorite drilling of about 5m as described in the 1st report. From the results of the test, it became clear that the new PDC core bit has potential to drill geothermal wells and that there is some room for improvement concerning the arrangement of PDC cutters on the bit. Two improved type new PDC core bits and one conventional type new PDC core bit with the same design as the bit used for the first field test, were fabricated. And field tests of these bits were repeated in a geothermal well called HDR-3, which was drilled adjacent to the HDR-2 well, in order to evaluate the performance of the bits. Formation drilled is basement rock of granodiorite and its temperature is estimated to be around 250°C. Five drilling tests using the three bits mentioned above were conducted at the depths between 1, 627m and 1, 907m under almost the same drilling conditions as the first test. One improved type and one conventional type bits drilled hot, abrasive and hard granodiorite of about 10 meters respectively at the penetration rate of about 0.5m/hr. The drilled length and the penetration rate of the PDC core bits were greater than those of surface-set diamond core bits. It became obvious that the new PDC core bit can be applied to geothermal well drilling from the results of the field tests conducted in two geothermal wells. The performance of the improved type bits could not be understood correctly due to failure of cutters from a bit body etc. However, taking all results into consideration, the improved type bit was estimated to have better performance as compared to the conventional type bit.