When a rich gas field is put into production, one has to decide on a production mechanism which may involve either depletion, or partial or full pressure maintenance through gas or water injection. In order to reach a decision, it is essential to know not only the thermodynamics of the condensates but also the Laws of their migration through the porous medium. This is achieved by a thermodynamic study, measurements of interfacial tensions between separate phases and by running a depletion experiment in bottom hole conditions. The interpretation of the set of measurements provides the necessary tools to run field scale simulations. We present the study of the fluid behaviour of one of our newly discovered fields, the results of which were integrated in a full field study to define the scenarios of possible field production schemes. The thermodynamic behaviour of the rich gas was represented by a Peng-Robinson equation of state involving seven pseudo components. The computed interfacial tensions between phases in equilibrium at different pressures ranged between .05 dyne/cm and 3 dyne/cm, they were very close to actual laboratory measurements. A depletion experiment was performed on a reconstituted 2 meters long core in bottom hole conditions (141 degrees C, 400 bars initial pressure), the pressure was decreased very slowly, at less than 1 bar/day, and several stops were imposed to observe pure gravity drainage. Only a small fraction of the condensates was produced but the liquid breakthrough was observed very early during the depletion. The experiment was history matched with a compositional model, relative permeabilities for gravity drainage were deduced. It was necessary to introduce a dependence of the relative permeabilities on interfacial tensions below a threshold value of .15 dyne/cm. Introduction When a field is put into production, primary depletion is the first mechanism to operate as the field pressure is decreased by fluid removal. For a gas condensate field, when pressure decreases below the dew-point value, a liquid phase condenses on the pore matrix and its concentration increases on a rather large span of decreasing pressure. Knowing the mobility of this condensate phase is extremely important in order to decide on the recovery scheme of the field. When the liquid condensate phase appears, the interfacial tension between the gaseous phase and the oleic phase is very low, in the order of several hundredth of a dyne. The interfacial tension steadily increases as the pressure is reduced. The effect of low interfacial tensions on the flow of fluids has been extensively documented. Many authors pointed out the influence of the capillary number on the trapped saturations for chemical systems; but, when the gas-oil systems are concerned, interfacial tensions rather than the capillary number seem to govern the trapping phenomena. P. 875^

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.

This study was undertaken to develop a method to reliably predict the performance of high relief carbonate reservoirs in the Rainbow Field (Alberta) -when produced by gravity controlled internal and external gas drives. These processes were invest-igated in the laboratory and a practical way of hand-ling the results for field predictions has been established for the external gas drive. For a medium GOR oil (800 scf/STB), primary depletion resulted in a complex diphasic flow with thermodynamical exchanges, which immiscible num-erical simulations were unable to match. INTRODUCTION Recent progress in laboratory technology has resulted in development of laboratory experiments which tend to reproduce the actual field conditions: (a) Actual core samples assembled in such a fashion as to make up a physical model representative of the reservoir under-study; (b) Reservoir fluids at reservoir pressure and temperature; (c) Fluid velocity in model similar to velocity in reservoir. Due to the low velocities and the complexity of the technology, the duration of such exper-iments ranges from several weeks up to about one year. The data f rom each experiment are analyzed with a numerical model in the same manner as for an actual field history. Since the porous media and fluid. properties and boundary conditions are well known, the adjusting parameters concern only the physics of the diphasic flow. They are the basic parameters which also control the productic,n mechanisms in the actual reservoir.Two experiments were conducted to simulate the gas pressure maintenance process and one the primary depletion process. Since gravity seg-regation controls the production in the high relief Rainbow reservoirs, all the experiments were perf'onned vertically with the ldroduction fluid withdrawr., from the bottom of the model. PHYSICAL MODELLING OF THE GAS PRESSURE MAINTENANCE (G.P.M.) PROCESS (a) EQUIPMENT AND PROCEDURE Figure 1 presents a diagram of the apparatus used in this study. Two physical models were used: a short model