The approach presented here is an attempt to implement the values of corrosion intensity which have been measured in laboratory tests, in the framework of the service life prediction analysis for corroding structures. First of all, the model on service life suggested by Tuuti was considered, and only the propagation period model has been analyzed in this paper. In order to expand the proposal, different steps were covered: (1) the definition of an unacceptable level of deterioration, taking into consideration the levels suggested by the Comité Eurointernational du Béton (CEB) in its Bulletin No. 162, in order to define the urgency of intervention in a damaged structure; (2) the reduction in bar diameter or bar section was taken as the determining parameter in failure risk, assuming that this decrease in section occurs either in a generalized form or in the zones of the structure in which the load-carrying capacity may be significantly affected; and (3) the ranges of possible corrosion intensity values were introduced in Tuuti's model for calculating the reduction in bar section in function of the life of the structure. Some examples for bars of 10 and 20 mm ϕ were presented. Finally, the limitations and the improvements of the proposal are discussed.

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The object of this study was to understand the enriched gas displacement process that is being applied in several kigh-relief carbonate reservoirs in Alberta. There is not yet sufficient field production history to determine the mechanisms affecting their performance. Therefore it is necessary to use laboratory data to show how the process works and the manner in which the various mixing zones develop and grow. Two programs were developed to study this phenomenon. The first was to define the behaviour of a simple three-component fluid system. The other was to use a multicomponent system in actual reservoir carbonate rocks performing the displacements at field pressure, temperature and rates. These experiments indicate that the solvent is not directly miscible with the oil but rather acts to change the composition of the oil. This change iscaused by the solvent contacting the oil and coming into thermodynamic equilibrium with it, forming two phases (liquid and gas). The velocity of the gas phase is greater than the liquid phase; hence, it moves ahead contacting new oil and coming into equilibrium with it. This exchange takes place until the gas at the front is in equilibrium with the original oil. These experiments showed that three zones develop. First there will be a zone having the composition of the original reservoir oil. The secondwill be a two-phase zone. This will be followed by a zone in which only a gaseous phase is flowing. The utility of these experiments is only to explain the displacement mechanism. The sizing of the solvent bank and recovery prediction must be made by numerical simulation. INTRODUCTION MISCIBLE FLOODING of a petroleum reservoir is defined as a displacement process which- has zero interfacial tension between the displaced and displacing fluids. There are two types of miscibility.Direct miscibility, where the two fluids form a single phase on first contact with each other.Conditional miscibility, where the fluids are not miscible on first contact but form two phases, with one of the fluids absorbing components from the other. After sufficient contacts and exchange of components, the system becomesmiscible. In summary, there are three general types of miscible displacements in active field use: LPG solvent, which is directly miscible with the reservoir oil; high-pressure gas, which is conditionally miscible with the reservoir oil; and enriched gas, which is conditionally miscible with the reservoir oil. Figure 1 is a constant pressure temperature pseudo-ternary diagram which is not thermodynamically rigorous but can be used to represent these three processes. The ternary representation is composed of four regions. The size and shape of these areas are determined by the dewpoint and bubble-point curves of the particular fluids being studied. Region A is a single-phase gas area, B contains two phases, C is a single-phase liquid area and region D is a single-phase fluid area.