The Development of Minami-Aga Oil Field

Abstract The various factors considered in evaluating gas cap gas expansion controlling operation in Minami-Aga field, which is located in Niigata Prefecture approximately 245 kilometers north west of Tokyo, are discussed. Prefecture approximately 245 kilometers north west of Tokyo, are discussed. The displacement efficiencies by zones, e.i., by water invaded zone, non-invaded zone and gas cap gas invaded zone, are calculated for the past performance. The predicted performance history under gas cap gas past performance. The predicted performance history under gas cap gas production and water injection is estimated utilizing both the material production and water injection is estimated utilizing both the material balance method and the frontal advance expressions. ORIGINAL OIL IN PLACE Volumetric Method The volumetric methods, as currently used, makes use of structural and iso-pachous maps based on data of electrical logs, cores and well tests. Sand volumes are obtained from an iso-pachous map and an area measured by planimetering. Core analysis data and interpretation of electrical logs planimetering. Core analysis data and interpretation of electrical logs permit reasonable estimates of porosity, connate water saturation and net permit reasonable estimates of porosity, connate water saturation and net pay thickness, and these enable to calculate the volume of hydrocarbon - pay thickness, and these enable to calculate the volume of hydrocarbon - filled pore space. The porosity of cores can be measured with a high degree of accuracy, but due to the limited number of core wells, the areal distribution of the porosity was not sufficiently defined. Therefore, in this field plots of porosity was not sufficiently defined. Therefore, in this field plots of porosity of cores and sonic transit time cumulative frequencies were made porosity of cores and sonic transit time cumulative frequencies were made on probability paper to calibrate of sonic log data to measured core porosities. porosities. Four satisfactory capillary pressure curves came from cores recovered from Well 23 and Well 36 as well as single-point irreducible water saturation analysis on other cores suggested that the water saturation was largely independent of the rock permeabilities. The irreducible water saturation was thus calculated based on core analysis data to be 40.4 per cent. Taking into consideration the gradual increase in water saturation in transition zone, the volumetric weighted average water saturation was calculated to be 42.42 per cent. Based on the available well test, production and electric log data, the original gas-oil contact was established at 1965 meters subsea and the original water-oil contact to be at 2235 meters subsea respectively. Net pay thickness in each well was determined on the basis of positive separation of the microlog, micro inverse and micro normal resistivity curves. The measured net thickness was then converted to vertical thickness, posted to a map, and finally a net isopachous map was constructed. The subsea contours of the gas-oil and oil-water contacts from the structural maps of the top and base of productive zone were then superimposed on the net isopachous map. Using "wedging" techniques described the Wharton, net isopachous maps were then prepared for both the gas cap and the oil zone. Finally, plots of cumulative gross rock volumes, net rock volume, pore volume and hydrocarbon pore volume versus structural height were made (Fig. 2.) And average porosity was calculated to be 23.5 per cent. Laboratory analysis data of fluid using the bottom-hole sample of Well 36 were corrected to the reservoir bubble point pressure at the time of discovery and the original formation volume factor was calculated to be 1.5407 vol/vol under the average field surface separation conditions. Original solution gas-oil ratio was also corrected to the field determined bubble point to be 166.5 std m3 of gas per k1 of stock-tank oil.