The subsurface temperature readings obtained from maximum temperature of electric logs (TES) generally do not indicate true subsurface temperature, and are lower than true subsur-face temperature because thermal equilibrium between bore hole mud and formation has not atta fined at the logging time. On the other hand, the temperature reading from bottom hole pressure measerment (TBHP) indicates almost true subsurface temperature. The subsurface temperature and geothermal gradient are important to consider terrestrial heat flow, generation and maturation of hydrocarbons, well cementing and casing programs, and reservoir fluid. The writers obtained two kinds of geothermal gradient, GGBHP from temperature of bottom hole pressure measerment and GGES from logging temperature, in several oil and gas fields of Niigata basin(Fig. 1). Average surface temperature was assumed to be 15°C. Although the gradients are different from every other fields, the ratio of GGBHP/GGES shows only small difference among the fields and is 1.31 on the average. Therefore, the following formula is derived TBHP=1.31(TES-15°C)+15°C More accurate subsurface temperature estimation will be made from TES by using above mentioned formula. Dowdle and Cobb (1975) recommended a method similar to the conventional pressure build up method for estimating true formation temperature from TES. The estimated formation temperature using their method as shown in their field examples and ours (Figs. 5, 6) is an excellent approximation to TBHP (almost true formation temperature). Therefore, in the future, this method should be used to estimate true subsurface temperature. The higher geothermal gradient obtained from our method assuming constant surface temperature merely means that certain higher temperature block such as volcanic bodies or basement rocks is present at shallow depth. The geothermal gradients obtained in the studied area, however, are well reflected in the underground structure and indicate high value at uplifted part and low value at subsided part(Fig. 9). It is necessary to accumulate the numbre of measurement of thermal conductivity in cores, especially sedimentary rocks in order to obtain terrestrial heat flow from geothermal gradient.
The lower Cretaceous porous units of reservoir horizon in the Mubarras oil field and it's surrounding have fairly good continuity but oil bearing reservoirs were found only in the restricted structures. These phenomena are attributed to timely concurrence of structural growth of oil reservoirs and oil migration into the structures. The structural growth of the main oil rese-rvoirs were studied by reconstructing the paleostructural maps of several stages through computer. The relations between the structural growth and present oil distribution in the reservoirs show that Thamama oil was entrapped in the reservoirs during the Campanian-Maestrichitian movement, namely, the peak of structural growth in the geologic ages. The depths and temperatures of the reservoirs at that time (age) were estimated at approximately 4, 000 feet and 60°F respectively. These conditions were recognized in some other fields and are applicable for exploration of new oil fields.
In this paper, a discussion is presented on the steam-flood performance, the residual oil saturation and the change of recovery owing to oil viscosity differences by steam injection in a reservoir model. The reservoir model was made of steel pipe 2 inches in diameter and 1m in length packed with silica sand and filled with oil. In the experiment, the flow performance of oil displacement was shown in three stages. The first one was distilled oil bank which was the end of the oil. The second one was a water bank following the oil which showed a constant flow rate and its water-oil ratio was about 3 to 4. Behind the water bank, the steam front just came in contact with it at the third stage. The flow rate suddenly increased just before steam broke through. The water-oil ratio after the break-through was about 20 to 40. The residual oil saturation was about 10% in the water bank just ahead of the steam front and gradually increased to 50% toward the distilled oil bank. Behind the steam front, the residual oil saturation was constant. The oil recovery was increased from 80 to 90%, depending on the decrease of viscosity.