The mechanisms of oil recovery by solution gas drive and by gas injection have been studied. The flow visualization experiments were performed in a high pressure heterogeneous micromodel reproduced from real rock micrographs. The micromodel was also employed in series with a compatible glass head pack. Pressure depletion and displacement experiments by methane, propane and water flooding were conducted on a live North Sea crude. The video observations and the measurements made are reported. The pore level investigation of solution gas drive revealed the mechanisms of nucleation, and the growth of gas bubbles at different pressure levels. The spontaneous movements of large bubble-oil interfaces contribute to the oil recovery process during the early stages of production. The recovery mechanisms at the higher gas saturations were found to be similar to be immiscible gas drive behavior observed with experiments of methane injection at low capillary numbers. The asphaltenes flocculation under dynamic conditions of oil displacement was studied by propane slug injection. The miscible displacement of oil by propane did not induce any significant asphaltene precipitation within the pores. Introduction Microscopic mechanisms of multiphase flow in porous media determine the oil recovery behavior. Visual microscopic studies under conditions similar to the real recovery processes in the reservoir can provide a valuable insight into the complex fluid transport mechanisms within the pore space of an oil reservoir. The mechanisms of oil recovery by solution gas drive have not been fully studied. A microscopic investigation of the recovery mechanisms can lead to a better understanding of the gas bubble nucleation and displacement behavior. Further the vast amount of reservoir engineering information generated during this mode of recovery may be used more successfully for gas injection studies when the mechanics of the recovery methods are more clearly understood. In an undersaturated oil reservoir, when the oil is produced and the reservoir pressure drops to the saturation point, the evolvement of the gas phase should occur. However, some degree of supersaturation may occur, i.e., the gas can remain in solution. As the formation and growth of gas bubbles are the essential features of the solution gas-drive mechanism, the nucleation phenomena is of considerable interest. Kennedy and Olso studied the formation of bubbles in a supersaturated mixture of methane-kerosene in a window cell packed with quartz and calcite crystals. Supersaturations expressed as the differences between the prevailing pressures and the bubble point up to 5.30 MPa (770 psi) were observed when the saturated liquid pressure was rapidly reduced. At supersaturation below 0.21 MPa (30 psi), no gas bubbles were observed even after 138 hours. Wieland and Kennedy investigated the nucleation phenomena in cores of different rock materials and noticed some degree of supersaturation for live oil mixtures. Chatenever et al studied visually the solution gas-drive mechanism of a mineral oil saturated with butane at atmospheric pressure in packed porous media. A state of supersaturation was reached before gas nuclei were observed. P. 233^

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The phenomena of retrograde condensation and the flow of gas-condensates in porous media under simulated reservoir conditions have been studied experimentally. Depletion tests on a 6 component synthetic gas mixture with a dew point of 33 MPa (4800 psi) at 37.8 degrees C were conducted in glass micromodels and long sandstone cores. Micromodels with homogeneous and heterogeneous patterns, were employed to observe the patterns, were employed to observe the mechanisms of gas-condensate flow at the pore level. The micromodelling results were then employed in designing experiments in vertical and near horizontal cores to study the phenomena at larger scale and in evaluating the recovery and composition of gas and gas condensates. The observations made on the micromodels revealed that whilst condensate continuity was maintained through thin films, its growth was observed to be non-uniform and strongly dominated by capillary and gravitational forces. The depletion tests on the cores verified pore level observations, and in particular, the minimum condensate saturation for the downward flow of condensate was found to be quite low. Implications of the results on gas-condensate laboratory experimental methods have been briefly discussed. Introduction In a rich gas reservoir or the gas cap of a volatile oil reservoir, the reduction of reservoir pressure below the dew point causes liquid to condense from the initially single phase fluid. The accumulation of condensate phase fluid. The accumulation of condensate usually leads to a significant drop in well productivity and the loss of valuable liquid productivity and the loss of valuable liquid reserves. The selection of the most suitable recovery scheme depends on the degree of understanding of various phenomena occurring in the reservoir during the various stages of recovery. It is generally believed that the flow behaviour of gas-condensate in porous media is different frost that of gas-oil and water-oil systems. However, the number of reported studies relevant to gas-condensate flow phenomena is very limited, and it is quite common to apply information, such as the relative permeabilities and the critical liquid saturation, generated frost related studies on gas-oil systems. Gasoline-nitrogen and water-gas systems have been used to simulate gas-condensate flow in cores resulting in a critical flow saturation ranging frost 30% to 50% of the pore volume. Saeidi and Handy studied the retrograde condensation of methane-propane mixtures, with a maximum liquid condensate saturation of 18%, in a horizontal sandstone core. No flow of condensate was observed with an interstitial water saturation of 30% or in the absence of connate water. They, however, found that the shapes of relative permeability curves far condensing systems and vapourising systems (oil-gas) were different. Gravier et al studied the condensate flow behaviour of a methane-pentane-nonane mixture in eight rock samples taken from a carbonate reservoir with permeabilities ranged from 0.5 to 40 10(-3)mu m2 permeabilities ranged from 0.5 to 40 10(-3)mu m2 (0.5 to 40 millidarcy). P. 527

Asphaltene deposits have been observed in a number of high gas-oil ratio (GOR) wells in north Ghawar. Even though the oil reservoir is undersaturated two small gas-caps are present as a result of gas injection during the 1960s and 1970s. New development wells drilled recently to produce oil and gas from the gas-cap areas have experienced asphaltene deposition. The cause of precipitation is the stripping of the asphaltenes from the crude by the gas. This paper describes the results of an investigative study that was initiated to determine the precipitation mechanism and ways to alleviate the deposition problem. Asphaltene precipitation experiments were conducted at reservoir conditions in a special PVT apparatus. The effect of gas-oil ratio on asphaltene precipitation was determined by titrating the reservoir oil with gas-cap gas. Bulk deposition tests were also performed at different GORs with reservoir fluids. The results demonstrate that the onset of asphaltene precipitation occurs at relatively low GOR values. However, the amount of asphaltene precipitated at the onset is negligible. Asphaltene precipitation and deposition increase with increasing GORs. Asphaltene deposition envelopes are provided for the reservoir oil as a function of pressure and temperature. Guidelines are provided to alleviate the problem by controlling the GORs. Recipes for solvent treatment including asphaltene dispersants are also described in the paper. Introduction Ghawar field is one of the major oil fields in Saudi Arabia. In the northern part of the field some wells have experienced solid built-up in the wellbore. Analyses of solid samples from several wells have shown the presence of asphaltenes that may have precipitated during crude production and have started to deposit on the wellbore. The solid deposition has been observed in high gas-oil ratio wells. A location map of the wells is shown in Figure 1 and photographs of the solid deposit from one well are shown in Figure 2. The Arab-D reservoir of Ghawar field contains an undersaturated light oil. The bubble point pressure is ~1,900 psi at the reservoir temperature of 215°F and the average gas oil ratio is ~570 scf/stb. The reservoir pressure at present is over 3000 psi. In the 1960s and 1970s the associated gases from part of the field were injected back into the reservoir at two locations due to unavailability of gas processing facilities and to avoid excessive flaring. The injected gases have formed two separate gas caps in the field (north and south gas-caps, Figure 1). In recent years oil production has started from these gas-cap regions. Due to the presence of the gas cap, some of the free gas flows into the oil production wells increasing their total gas oil ratios (GORs). The coning or cresting of gas into the oil has caused limited plugging in a few wells in the north and south gas-cap areas. The gas strips the oil of asphaltenes which precipitate and deposit in the wellbores. Plugging of the wellbore by asphaltenes or organic deposits has the potential to reduce productivity and cause production impairment. Furthermore, several more gas-cap wells are being planned to be drilled in the area and their productivity may be impacted by the deposition tendency. Figure 3 shows the GOR for 11 wells in which asphaltene deposits have been observed. The solid line shows the average GOR for the entire field (~570 scf/stb). Except for one well, the GOR for all wells is higher (in some cases substantially higher) than the average field GOR. The high GOR is a consequence of gas coning/cresting in the wells. The free gas strips the asphaltenes from the crude which deposit in the wellbore. One well was tagged over a period of time to ascertain the buildup of asphaltenes in the well. Figure 4 shows the tag depths and indicates a loss of wellbore accessibility of ~200 ft over a period of 18 months. Recent results show that the buildup has stabilized and the asphaltenes may be dragged with the oil to the gas oil separating plant (GOSP). Other wells are also being monitored and have shown some buildup activity.

In contrast to near-wellbore conformance control applications, polymer gels are applied in injector wells for reservoir scale applications for in-depth fluid diversion (IFD). Novel gel systems include weak gels, sequential injection for in-situ gels, colloidal dispersion gels, preformed gels, and microgels. The objective of an IFD process is to modify the prevailing reservoir inflow profile by gel treating the reservoir to significantly reduce effective permeability of high permeability zones that would otherwise dominate the water uptake. The weak gels or gel particles are treated as a flowing fluid and are custommade for reservoirs with fractures or high permeability zones. The very weak gels form near the wellbore region, but continue to propagate into the reservoir. The gels eventually stop propagating deeper into reservoir due to the variation in pressure gradients and pore structures. The subsequent injection of fluids, water or chemical solutions, will redirect predominate flow paths to unswept reservoir zones, which improves oil sweep efficiency by waterflood (or chemical flood); thus, leading to enhanced oil recovery. The technology presents distinctive advantages to high-salinity and high-temperature reservoirs as compared to polymer flooding due to stability of cross-linked gel structures.This paper presents a state-of-the-art review of IFD technologies including weak gels, sequential injection for in-situ gels, colloidal dispersion gels (CDG), microgels, and preformed particle gels (PPG). Moreover, a solution to the challenges of IFD applications in high-salinity and high-temperature reservoirs is presented.