This paper presents a Reservoir Engineering Study of Block 6, Emlichheim Field, West Germany. Well pressures, water cuts and temperatures during both cold and hot water injection were matched using a numerical three-dimensional model that simulates the process of hot fluids injection. Prediction runs were made to investigate the effect of injection location on oil recovery for steam injection. One set of relative permeability curves that is independent of the temperature level was used to match field reported residual oil saturations behind cold water, hot water and steam fronts.


Simulation models for predicting reservoir performance of thermal recovery projects are now available. These models describe and treat fairly rigorously the different recovery mechanisms that take place in such situations. Effectively using such tools requires a knowledge of the rock and fluid properties and a good reservoir description. Fields with relatively long producing histories give needed confidence in the accuracy of the rock and fluid properties and reservoir description, provided that a successful match of calculated and observed field behavior can be obtained. This was the case in the Einlichheim-block No. 6 study. The model used in this study is described by Coats et al1. The Block No.6 reservoir is sealed from the rest of the Emlichheim field by three main faults. This block has 17 MMSTB of oil-in-place. Production started in 1944 and cold water injection started in 1960 in two wells. In 1967 cold water injection was stopped. Hot water was injected into one well and has been continued until the present. By the end of 197q this block had produced 3. 75 MMST8 of oil which represents 22 percent of the initial oil-in-place.


Block No. 6 is sealed from the rest of the Einlichheim field by three main faults as shown in Figure 1. The structural elevation and thickness maps are shown in Figures 1 and 2 respectively. The oil accumulation is in contact with a large aquifer to the south. However, the effectiveness of the aquifer is restricted by a minor fault that closely coincides with the oil-water contact. Water was injected about1200ft south of the oil-water contact. This suggested that a sealing fault existed within this 1200 ft.

The reservoir rock is a sandstone with average porosity of 27 %and permeability that ranges from several darcies at the top of the pay to 100 md et the bottom. Average sand thickness is about 90 feet and the oil column is about 350 ft.

The oil viscosity, Table I, varies from 180 cp at 100 °F to 3.2 cp at 350 °F. The initial reservoir pressure is 1273 psi and the bubble point pressure is 390 psi. The work done in this study did notaccount for any gas evolution. During the producing history the pressure did fall below the bubble point pressure. However, the reservoir pressure in all of the prediction cases considered was well above thebubble point pressure.

Other basic reservoir data are listed in Table II.

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