In this study, gas-oil gravity drainage process and steam-gas assisted gravity drainage processes for heavy oil recovery from fractured models were investigated experimentally. For each test, six oil- wet saturated outcrop cores, 8.7 cm in diameter and 15 cm length, were stacked in a long core holder. In the first step, gas injection was started into the model at reservoir condition that results in oil production under gas-oil gravity drainage mechanism. In the second round of tests when no more oil was produced by gas injection, the tests were continued using steam-gas assisted gravity drainage process. In this stage, gas was injected together with specific steam/gas ratio at saturated temperature condition. In the course of experiments, oil and water productions, pressure and temperatures of system were monitored carefully. The experiments were performed using three different combination of gases consist of pure CO2, pure N2 and mixture of 15 % CO2 and 85% N2 as synthetic flue gas. The results showed that after gas breakthrough and fracture depletion, the ultimate oil recovery for CO2 injection was 58.4 % (14.8% for gas injection and 43.6 % for steam-gas co-injection), in the case of flue gas injection, it was 73.8 % (9.8 % for gas injection and 64% for steam-gas co-injection) and for N2 injection was 47% (13.5 % for gas injection and 33.5% for steam-gas co-injection). The results indicate the high performance of flue gas injection for heavy oil recovery from fractured reservoirs during gas-oil gravity drainage and steam-gas assisted gravity drainage processes.
Wettability is known as the relative tendency of a fluid to wet a solid surface in the presence of another fluid that coexists in a system. Oil recovery efficiency of an oil-wet rock, mostly fractured carbonate formations, could be improved by the spontaneous imbibition of water if the rock wettability is changed. In this study, contact angle measurement was used to investigate the effects of aging time in crude oil as well as those of steam exposure on the wettability of calcite, mica, quartz, and glass surfaces.
The effects of rinsing the aged surfaces with different solvents on wettability were also studied to check the accuracy of the method and the contact angle measurements process utilized in this work. Different results of wettability alteration were observed when the mineral surfaces aged in the crude oil were exposed to steam. Quartz, calcite, and glass surfaces regained their original water wetness , while mica surfaces showed a tendency toward increased oil wet behavior. Among the tested minerals, calcite surfaces yielded the least wettability alteration when exposed to steam. Glass micro-models were also used to investigate the effect of steam and hot water injection on their wettability. Results of fluid distribution and residual oil saturation in micro-models showed that the wettability changed toward water-wet during steam and hot water injection.
Wettability alteration is believed to be the key mechanism of additional oil production from unconventional and depleted oil resources. It was pointed out that a change in wettability, from a strongly wetting condition to a moderately wet state (neutral wettability), leads to more oil production in non-fractured rocks [1, 2]. On the other hand, wettability alteration toward more water wetness leads to more oil recovery due to capillary imbibition of water into the matrices of fractured rocks, and prevents
the re-imbibition of oil into the adjacent matrices. In this view, more oil is produced if the wettability is altered artificially towards a suitable state, depending on the nature of the oil recovery process.
It is wise mentioning that wettability alteration is a feasible scenario through careful employment of conventional enhanced oil recovery processes such as the thermal methods [3-8], however the mechanism of the alteration should be known precisely.
Thermally induced wettability alteration had been the heart of several studies but remained a puzzle for many years, However, There are still uncertainties regarding the effects of temperature on wettability: it is not exactly known how a change in temperature induces wettability alteration. Ayatollahi et al.,  showed experimentally that wettability alteration due to thermal methods of oil recovery is the main reason behind the different reported performances of these techniques. Rao  stated that in most cases, sandstones became more oil-wet, while most carbonates tended to show water-wet behavior at high temperatures. In agreement with Rao's belief, which is frequently repeated in the preceding literature, Al- Hadhrami and Blunt , showed conclusively that an increase in temperature resulted in a more water-wet carbonate rock. They concluded that this scenario is the best choice for the production of a substantial amount of oil that is trapped by capillary pressure in the matrices of fractured carbonate reservoirs of Middle East. They have stated that this scenario can even be implemented for recovery of light oil from fractured reservoirs. In contrast, it was shown experimentally that an increase in temperature due to thermal oil recovery induces water-wetness in Berea sandstone and diatomite rocks [5-7].
Asphaltenes are undoubtedly one of the important difficulties in the oil industry; its precipitation can impose specific affects on the productivity of the producing zone, as well as in the surface facilities and transportation lines. The main in situ consequences are their effect on the permeability by pore blockade, and on the wettability alteration by surface precipitation.
In this paper, thermally induced wettability alteration is studied experimentally. The changes in the rock mineral content after imposing heat as the effect of thermal oil recovery are also studied using XRD. The results verify that asphaltene precipitation could be considered as the main platform for wettability reversal and the permeability reduction in the treated zone. The results also clarify the contradictory doubts around wettability alteration during thermal treatment in the literature. The experimental data shows that the media is gradually altered to strongly oil-wet in the temperature range of 150 - 400oC and subsequently changed to water-wet as the temperature increased.
Furthermore, the effects of temperature on asphaltene destabilization and precipitation is studied and the required thermodynamic criterion for asphaltene precipitation is found. The asphaltene precipitation in the formation by the thermal oil recovery techniques is thermodynamically modeled using regular solution theory.
The simulated date obtained using the model verifies by the experimental results. The model shows that as formation temperature increases toward crude oil's bubble point, its molar volume increases and solubility of the asphaltene decrease. This leads to asphaltene precipitation, and alteration of wettability toward strongly oil-wet condition. At temperatures higher than the crude oil bubble point, precipitated asphaltene start to dissolve, mainly due to evaporation of crude oil saturates. This stimulates a wettability shift toward more water-wet condition.
Thermal oil recovery and oil recovery at elevated temperatures are practical and valuable in the current circumstances. Considering the current very high oil prices, and the abundant potential of thermal recovery all around the world, it becomes more and more attractive in the commercial oil production scales and in the field of technical studies. As the hot front passes through the reservoir, with respect to high temperatures, fluid composition, and the rock mineralogy, some accelerated physical/chemical reactions tend to amend reservoir properties. It is practical to summarize such changes as crude oil in-situ upgrading (Hongfu, et al., 2002; Castanier and Brigham, 2003; Hongfu, et al., 2004), mineral alteration (Huang and Longo, 1994; Ma and Morrow, 1994; Lore, et al., 2002), wettability alteration (Al-Hadhrami and Blunt, 2001; Ayatollahi et al., 2005; Schembre et al., 2006; Escrochi et al., 2007), and changes in other petrophysical properties (Day et al., 1967; Ma and Morrow, 1994).