Enhanced oil displacement in a reservoir is highly affected by wettability alterations in conjunction with the lowering of viscosities during steam assisted gravity drainage (SAGD) for bitumen extraction. The impartation of energy in the form of heat to the fluid by injecting steam triggers an alteration to a more water-wet state during SAGD. However, the presence of three distinct phases in the reservoir has implications for the effective modeling of the complex fluid dynamics. Dependency of the relative permeability endpoints on the temperature realized as a function of the introduction of steam is difficult to model. Optimization of any steam process requires simulation in order to adequately characterize years of flow and so a model that is capable of representing three phase flow is necessary. To obtain this a pseudo-two phase relative permeability is proposed that assumes fractional flow theory is valid and treats the experiments as a waterflood.
In this study, experimental recovery data for two SAGD experiments and one hot water flood are empirically matched by manipulating relative permeabilities. The analytical approach implemented allows for the representation of fluid flow in the reservoir by achieving a pseudo-two phase relative permeability that results in comparable performance to the experiments. Waterflooding techniques were utilized which allowed for the negation of the steam phase in the model and so two-phase flow was established.
The sensitivity of the relative permeability curves to temperature change results in the inability to formulate a generic three-phase curve and so the pseudo-two phase curve is valuable for the purpose of simulation. The methodology presented enables the formulation of a simplified relative permeability that is unique to each process used and in that specific location. The model that was established was validated and proven credible by the good match with the experimentally obtained values.
The Green River, Utah holds the world's greatest oil shale resources. However, the hydrocarbon, which is namely kerogen, extraction from shales is limited due to environmental and technical challenges. In this study, we investigated the effectiveness of the combustion process for shale oil extraction. Samples collected from the Green River formation were first characterized by X-ray Diffraction (XRD) and Scanning Electron Microscopy (SEM). Then, series of dry combustion tests were conducted at different heating rates and wet combustion tests by water addition. The combustion efficiency was enhanced by mixing oil shale samples with an iron based catalyst. The effectiveness of dry, wet, and catalyst added combustion processes was examined by the thermal decomposition temperature of kerogen. Because the conventional oil shale extraction methods are pyrolysis (retorting) and steaming, the same experiments were conducted also under nitrogen injection to mimic retorting. It has been observed that the combustion process is a more efficient method for the extraction of kerogen from oil shale than the conventional techniques. The addition of water and catalyst to combustion has been found to lower the required temperature for kerogen decomposition for lower heating rate. This study provides insight for the optimization of the thermal methods for the kerogen extraction.
Once a shale gas condensate reservoir is produced, the reservoir pressure falls below the dew-point pressure, and the condensate liquid will be formed in the pore space; the condensate can then accumulate near the wellbore. This condensate blockage would reduce the gas relative permeability and decrease the gas production. The condensate is formed by the heavy components in reservoir fluid, and these heavy componenets are very valuable economically in the industry. Therefore, operators are seeking ways to maximize condensate recovery from gas-condensate reservoirs.
Huff-n-puff gas injection is an effective approach for enhancing condensate recovery in shale gas condensate reservoirs, as shown by our earlier papers (
In this experimental study, a binary gas condensate mixture was used to investigate the dominant mechanism. The core was saturated with a gas condensate mixture at 2200 psi to simulate the initial reservoir condition. Then, the pressure was depleted to 1500 psi, which was lower than the dew point pressure. During the depletion, the produced gas was collected in a vacuumed gas sample bag. After depletion, the huff-n-puff method was applied. After every cycle of huff-n-puff, the produced gas was collected. GC was used to analyze the compositions of the different gas samples. Also, a CT scanner was used to determine the condensate saturation in the core. From the GC analysis, by comparing the gas sample after primary depletion with the gas sample after the first cycle, it was found that the heavy component-butane increased significantly. This means that most of the heavy components of condensate were revaporized and flew out with the dry gas. This proves the revaporization mechanism of the huff-n-puff gas injection.
Our experiment results show that huff-n-puff was an effective way to enhance the condensate recovery, and revaporization was the main mechanism of huff-n-puff. When the pressure was increased in the huff process, the heavy components were revaporized and flowed out with gas in the puff process. Though in the gas flooding method, the reservoir pressure was also increased, but the near-wellbore pressure was not increased very much in the shale gas reservoirs; thus, heavy components would still be formed near the wellbore. However, in the huff-n-puff method, because of the same well, the pressure near the wellbore would be higher than the dew point pressure in the beginning of production process. Therefore, the heavy component would be recovered with gas. Our GC results visually showed the revaporization mechanism of huff-n-puff in the shale gas condensate.
The use of isenthalpic flash has become of interest for the simulation of some heavy oil recovery processes where large temperature changes are experienced. For these thermal simulations energy can be used as a primary variable. This leads to thousands or millions of individual multiphase isenthalpic flash calculations. Robust and efficient algorithms for multiple-phase isenthalpic flash are required to improve the efficiency of compositional simulations for thermal recovery.
The general framework on state function based flash specifications proposed by
Narrow boiling mixtures can be dealt with in the majority of cases without any significant difficulty. This is true of the direct substitution algorithm and the proposed solution procedure. The vast majority of examples can be solved without using Q function maximisation. The challenges associated with multiphase calculations in the Newton steps are investigated. In particular, inadequate initial estimate of the equilibrium type may lead to non-convergent iteration. This can usually be solved by introduction of a new phase and/or elimination of an existing phase. The speed of the method is analysed for a large number of specifications and is found to be only slightly more expensive than isothermal flash in the majority of cases.
When compared with steam-assisted gravity drainage (SAGD) operations in the McMurray Formation, Athabasca Oil Sands, SAGD projects in the Clearwater Formation at Cold Lake did not perform as expected, likely because of reservoir properties. This paper will use the Orion SAGD case study to: (1) investigate the impacts of reservoir properties on the SAGD thermal efficiency by field evidences; (2) identify key geological parameters influencing each well pad; and (3) summarize major geological challenges for Orion SAGD expansion.
Wireline log data were interpreted to characterize reservoir properties, which were used to build 3D models. 3D visualizations and 2D cross sections of the reservoir revealed spatial distribution and heterogeneity of each property. SAGD production performance was analyzed using: (1) temperature profiles that monitored the growth of the steam chamber; (2) cumulative steam-oil ratios (CSORs); and (3) oil production rates (OPRates), which are direct indicators of thermal efficiency.
Results show that impermeable barriers and low-permeability zones were detrimental to steam injectivity and steam chamber growth, as observation wells in Pilot Pads 1 and 3 did not detect any steam saturation. High-permeability zones favored high steam injectivity and mobility, especially in Pad 105. Steam chambers were irregularly shaped by high shale-content zones, as two sharp spikes displayed on the temperature profile in Pad 103. Low oil-saturation zones and thin net-pays increased the CSORs, as seen in Pads 106 and 104. Impermeable barriers are almost horizontal, making no difference on well pad orientation by their dip angles. Lack of porosity variation made it difficult to identify the impact of porosity on each well pad.
The relatively extensive distribution of impermeable barriers between and above well pairs, as well as the relatively large area of low oil saturation and thin net-pay, were identified as major geological challenges.
The production and transportation of heavy and extra-heavy crude oil are two of the paramount concerns in the oil industry due to the difficulties associated with heavy crude oil high viscosity. One of the most efficient techniques to improve the recovery and the transportability of such oil is to reduce its viscosity through dilution that can be applied solely or via thermal methods.
In the present work, a new type of plant-based diluent is proposed, and its efficacy in heavy oil viscosity reduction for different concentrations, temperatures and shear rates is studied. Various concentrations of diluent, ranging from 5 to 25 wt%, are added to heavy-oil samples with different concentrations of asphaltene and viscosity, ranging from 48000 to 65000 cp in ambient temperature. A rotational viscometer was then employed to the measure viscosity of the prepared samples at the temperature range of 70 to 190°F and a shear rate of 3 to 50 s-1.
The application of the proposed diluent led to promising results in that in caused the viscosity of the heavy oil samples to reduce by 93% in 75°F and 85% in 190°F with 20 wt% of diluent. To compare the performance of the proposed solvent and the common viscosity-reducing solvents, heavy oil samples were diluted with xylene and toluene with the same concentrations. Results indicated that the application of proposed diluent outperformed all of the commonly used solvents in terms of decreasing viscosity. The application of 20 wt% of the proposed diluent led to a 93% viscosity reduction of the heavy oil samples, which is 15% more than efficiency of adding the same concentration of toluene.
The proposed diluent is a plant-based, non-hazardous substitute to the conventional hazardous diluents, e.g., xylene or toluene, that provides more efficient viscosity reduction compared to its conventional alternatives. Its flashpoint is higher than that of light crude resulting in less evaporation at high temperatures thus a longer period of reduced viscosity can be obtained. Furthermore, due to its high flashpoint, the proposed diluent can be employed in thermal methods more efficiently.
By coupling heat and mass transfer for C3H8–
Solvent Aided-Steam Flooding (SA-SF) focuses on maximizing the oil production by reducing the economic and environmental challenges created by steam generation. However, the solvent selection is vital due to the interaction of solvents with asphaltenes. Moreover, the polar nature of asphaltenes also enables asphaltene-steam interaction which may result in emulsion formation. This study investigates solvent-asphaltene-steam interaction during SA-SF with low and high molecular weight asphaltene insoluble solvents.
Two different solvents were tested; n-hexane (E1 and E4) and a commercial solvent (CS) (E2 and E5) with four flooding experiments; two miscible flooding (E1 and E2) and two SA-SF (E4 and E5) experiments. Results were compared with steam flooding (E3) experiment. The performance evaluation of different enhanced oil recovery methods was accomplished by comparing the oil recovery rates. The asphaltene content of produced oil samples was determined by standard methods. The asphaltene-steam interaction was analyzed with microscopic images, and the water content of produced oil samples was measured by Thermogravimetric Analysis (TGA).
Even though similar cumulative oil productions were obtained by the end of E1 (n-hexane-flooding) and E2 (CS-flooding), the produced oil quality varied due to asphaltene and clay contents. While higher clay content was measured for E1, E2 had a lower quality, due to higher asphaltene contents. This finding is due to the heavy dearomatized hydrocarbons composition of the CS which ranges from C11 up to C16 and enables more asphaltene production. Even though, E5 yielded the highest liquid production among all experiments; the produced liquid was composed of emulsified oil. The solvent aided-steam flooding (SA-SF) experimental results, which have been conducted with n-hexane/steam (E4) and CS/steam (E5) injections, suggest that as the asphaltene content increases in produced oil samples, more hard-to-break emulsions are formed. The unusual stability of these emulsions can be attributed to the nature of the asphaltene present in the produced oil.
From the results presented, it is recommended the use of lower carbon number solvents to leave the larger amounts of asphaltenes in the reservoirs. The solvents differed in their interactions with the asphaltenes present in the oil and with the steam that has a direct impact not only on the quantity of oil produced but the quality as well. Hence, the wise selection of the appropriate solvent cannot be ignored during solvent aided-steam flooding processes.
Franco, C. A. (Universidad Nacional de Colombia - Sede Medellin) | Cardona, L. (Universidad Nacional de Colombia - Sede Medellin) | Lopera, S. H. (Universidad Nacional de Colombia - Sede Medellin) | Mejía, J. M. (Universidad Nacional de Colombia - Sede Medellin) | Cortés, F. B. (Universidad Nacional de Colombia - Sede Medellin)
Heavy (HO) and extra–heavy oil (EHO) production is complicated due to its high asphaltene content that lied to adverse rheological properties. In addition, the upgrading of these unconventional oils at surface or sub-surface conditions is a low cost-effective process because of the large amounts of energy needed. Accordingly, several in-situ techniques for enhancing HO and EHO recovery with objective of upgrading the oil and improving its viscosity and mobility have been employed. In this sense, nanoparticulated catalysts have demonstrated a synergistic effect in the enhancement of oil recovery and the improvement of the pyshicochemical properties of HO and EHO such as viscosity, API gravity and content of heavy hydrocarbons such as asphaltenes. Hence, this work aims at investigate the effect of catalytic active nanoparticles in the improvement of the efficiency in recovery of a continuous steam injection process.
Nanoparticles were selected trough batch-adsorption experiments and the subsequent evaluation of the temperature for catalytic steam gasification in a thermogravimetric analyzer. A nanoparticulated support was functionalized with 2 wt% of NiO and/or PdO nanocrystals in order to improve the catalytic activity of the nanoparticles.
Also, successfully a methodology for evaluating the effect of nanoparticulated catalyst in processes of continuous vapor injection was developed. Oil recovery was evaluated using a slim tube filled with a non-confined sand pack in steam injection scenarios in absence and presence of a water-based nanofluid. The displacement test was carried out by (1) constructing the base curves, (2) estimating the oil recovery by the continuous injection of vapor in absence of nanofluid and (3) identifying the influence of the nanoparticles in the enhanced recovery of oil.
It was found that functionalized nanoparticles lead to higher adsorption of asphaltenes, higher degrees of asphaltenes self-association and lowered the temperature of