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Collaborating Authors
Ayatollahi, Shahab
Effect of MgO Nanofluid Injection into Water Sensitive Formation to Prevent the Water Shock Permeability Impairment
Habibi, Ali (IPE, University of Tehran) | Heidari, Mohammad A. (Islamic Azad University (S&R Branch-Tehran)) | Al-Hadrami, Hamoud (Sultan Qaboos University) | Al-Ajmi, Adel (Sultan Qaboos University) | Al-Wahaibi, Yahya (Sultan Qaboos University) | Ayatollahi, Shahab (EOR Research Center, Shiraz University)
Abstract Fines migration is the major reason for productivity decline known as formation damage in oil reservoirs. Sandstone formations are sensitive to brine salinity alteration which disturbs equilibrium condition in porous media. Because of nonequilibrium condition fines migration occurs during various operations. Nanoparticles seem to be good candidates to strengthen the attractive forces between fines and pore wall due to very small size, high specific surface area and electrical surface charge. In this experimental study, several tests were performed using Berea sandstone (8 wt% clays) cores (3 in. length and 1.5 in. diameter). MgO nanoparticles were stabilized in the water uniformly using surface active agent and ultrasonication. Total dimensionless energy of interaction between nano particles in the suspensions was calculated based on the DLVO theory. Various core flooding tests were conducted to determine the effect of MgO nanofluid injection as clay stabilizer at different brine salinities on the cores with the permeability from 600-100 md. The pressure drop across the core was measured. The results indicated that the MgO nanofluid could fix fines effectively where brine salinity became lower than CSC. Besides, measured zeta potential and total energy of interaction calculation confirmed that repulsive force became dominant at the specific concentration of the complex nanofluid which ensures its stability for long time during core flooding tests. Thus, MgO nanofluid significantly prevented water shock problem. Also, no significant reduction in permeability was noticed in any of core flood tests.
- North America > United States > West Virginia (0.26)
- North America > United States > Pennsylvania (0.26)
- North America > United States > Ohio (0.26)
- (2 more...)
- Research Report > New Finding (0.67)
- Research Report > Experimental Study (0.48)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.78)
- Geology > Mineral > Silicate > Phyllosilicate (0.56)
Abstract The concern over fossil energy shortage for the next decade leads to the extensive research activities in the area of enhanced oil recovery. Steam injection as one of well known EOR process has been used for about five decades to improve the oil production rate and recovery efficiency. Steam flooding is applied to heavy and extra-heavy oil reservoirs; however it could be used in light oil reservoirs in which water injection do not work effectively. Regardless of different performances, this method is an efficient EOR process for both heavy and light oil reservoirs. In this work, two separate numerical models were prepared to investigate steam flooding performance for the recovery of light and heavy oil. The heavy oil model is a Cartesian hypothesis model with properties of Cold Lake heavy oil reservoir in Canada and light oil model is a sector of an Iranian fractured light oil reservoir. For this purpose, steam flooding was implemented in these two models separately. Then according to software options, all possible recovery mechanisms (viscosity reduction, steam distillation, thermal oil expansion and others) were simulated individually to measure the effectiveness of each recovery mechanism in total recovery of heavy and light oil during steam flooding. Also, operational parameters such as steam quality, steam flow rate and well perforation were optimized for both reservoirs. Results show that steam flooding performances in heavy and light oil reservoirs are different. Heavy oil reservoirs do not response fast to steam compared to the light oil reservoirs. Furthermore, viscosity reduction is a main recovery mechanism in recovery of heavy oil and contribute to 80% of total recovery, while in recovery of light oil all three main recovery mechanisms have the same contribution to total recovery. It was also found that the optimized operational parameters are different for each reservoir.
- North America > United States > California (1.00)
- North America > Canada (0.89)
- Asia > China (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- North America > United States > California > Los Angeles Basin > Wilmington Field (0.99)
- North America > United States > California > Los Angeles Basin > Brea Field (0.99)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract Formation damage in oil reservoirs as a result of fines migration is a major reason for productivity decline. Fines loosely attached to the pore surface are in the equilibrium with the pore fluids. These particles start to flow when the equilibrium state is disturbed which, may end up in permeability reduction in porous media. Different solutions have been suggested to prevent detachment of fines from surface such as acidizing, ionic clay stabilizer, polymers and etc. Nanofluids containing metal oxide nanoparticles show specific properties. They have various applications including catalysis, waste remediation, additives in refractory and paint products. Our previous published works showed that MgO nanoparticle could be used as the best adsorbent of the fines in s synthetic porous media. In this work, Unit Bed Element (UBE) model and material balance were proposed to describe the effect of nanoparticles presence on fines fixation. UBE model relates dimensionless parameters of surface forces to fines removal efficiency of porous media. Material balance modeling provides an estimation of effluent fines concentration based on the injected fluid flow rate. Also the main mechanism for this fixation has been studied by surface forces analysis. Results show that soaking the core for 24 hours with 0.1% wt MgO nanofluid and water injection with 800 cc /hour could fix the fines which could used in particles release rate calculation in porous media. UBE and material balance modeling showed that the experimental results are trustable. Introduction Fines migration is a challenging problem in the production from oil reservoirs. Fines are feeble particles present in the porous media, which can detach and move easily due to fluid flow. Flow of suspension causes formation damage because of filtering at pore-level in the porous media (Muecke, 1979; Vaidya, et al, 1990; Civan, et al, 2007). Colloidal and hydrodynamic forces are found to be responsible for the fines detachment and their release from the pore surfaces. London Van der Waals attraction, double layer and Born repulsion and hydrodynamic forces are the dominant forces in the detachment of fines from porous media (Khilar, et al, 1998; Schramm, et al, 1996; Ahmadi et al, 2011). Hibbeler et al, (2003) provide an excellent review on the practical recipes to reduce fines migration.
- North America > United States (0.46)
- Europe > Netherlands (0.28)
- Asia > Middle East (0.28)
- Research Report > New Finding (0.67)
- Research Report > Experimental Study (0.66)
Abstract 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. Introduction 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 . 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 , 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 .
- Asia > Middle East > Iran (0.29)
- North America > United States > West Virginia (0.24)
- North America > United States > Pennsylvania (0.24)
- (2 more...)
- Geology > Mineral > Carbonate Mineral > Calcite (0.68)
- Geology > Mineral > Silicate > Tectosilicate > Quartz (0.48)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.45)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.72)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (2 more...)