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Results
Summary Previously, nuclear-magnetic-resonance (NMR) carbon-type-analysis data were used to develop a mathematical model of mild thermal conversion (visbreaking) of Athabasca bitumen (Chan et al. 2006). In that work, the major reaction pathways followed during visbreaking were identified. This approach is being extended in the current work to model the visbreaking behaviour of five different oils from different geographical locations around the world. This paper shows the correlation of residue conversion with the contents of different carbon types for five heavy oils from four continents. During visbreaking runs, operators intend to maximize process yields. This is achieved through increasing process severity by raising temperature. However, if the temperature is too high, coke forms. This maximum temperature varies with different crude oils; therefore, as refinery feedstock composition changes, so does the onset of coking temperature. Coke is a hydrocarbon material that has low hydrogen content and is insoluble in the oil. Consequently, this precipitates in the reactor, eventually causing an unscheduled unit shutdown. We have found that contents of specific carbon types in the feed oils correlate with coke formation. This correlation allows prediction of the quantities of coke that will form under the chosen visbreaking (mild thermal) conditions and the "maximum" quantities of coke that would form under coking (severe thermal) conditions.
- Europe (0.93)
- North America > United States (0.68)
- North America > Canada > Alberta (0.32)
- Energy > Oil & Gas > Downstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.77)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (0.86)
Summary The commercial viability of the steam-assisted gravity-drainage (SAGD) process is affected negatively by several undesirable reservoir features, such as pronounced heterogeneity, low vertical permeability, thick and areally extensive shale barriers, and steam thief zones. The efficiency of SAGD projects is also affected by the presence of higher water saturation in the target zone. Although the presence of small mobile-water saturation is not considered harmful, reservoirs with high water saturation may be poorly suited for the SAGD process. Nonetheless, SAGD remains the only practical technology for in-situ extraction of oil from oil-sand reservoirs, even when mobile water is present. This raises the question of how much mobile water is prohibitive. To investigate the effect of water saturation on SAGD performance, high-pressure physical-model experiments were carried out. Different levels of water saturations were established in the model by modifying the packing and saturating techniques. SAGD experiments were carried out by injecting superheated steam at controlled rates and producing the oil from the production well at constant pressure. The injection rate was selected to keep the pressure difference between the injector and the producer at a low level. The oil-production behavior was analyzed to evaluate the effect of water saturation on the thermal efficiency of the process. On the basis of the results of low- (immobile) and high- (mobile) water-saturation experiments, it was observed that the oil-recovery factor dropped by 6.6% when the initial water saturation was increased from 14.7% to 31.8%.
- Asia (0.67)
- North America > Canada > Alberta (0.16)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.34)
Summary The solvent-aided process (SAP) is a solvent-based enhancement of steam-assisted gravity drainage (SAGD) in which small amounts of solvent, such as light alkanes or natural-gas liquids, are added to the injected steam to enhance reservoir performance and associated project economics. Expectedly, the economics with SAP are sensitive to the solvent recovered from the reservoir, making its measurement in a field test an important factor. When a single-component solvent such as butane, which is not generally present in the produced heavy oil or bitumen, is used in SAP, estimation of the recovered solvent can be achieved uniquely. But when the solvent also has heavier components, some of which overlap with the lighter components of the produced oil, the measurement is not straightforward. The problem is compounded by the fact that the interaction with the reservoir changes the composition of the produced solvent and makes it time variant on account of different resident times associated with different components. The issue is further complicated by the fact that produced oil also undergoes an in-situ solvent deasphalting process (SDA), which is also time and space variant in the reservoir. If there were no in-situ SDA, one potential method to measure the amount of produced solvent would be to measure the total asphaltene content as an oil "marker" in the produced blend. Use of a tracer with injected solvent, as well as regression-based analyses for solvent fraction (using compositional analyses of solvent, bitumen, and the blend) of the produced blend, is error prone for these same reasons. Because of the issues in these approaches, a new method is desirable for a more-robust and unique assessment of the solvent amount in the produced fluids. This paper elaborates on the current challenges and proposes a couple of workable methods, including use of maltenes/metals content as oil markers as well as the use of boiling-point curves of the produced blend compared with the boiling point of the base oil. Such techniques of estimating the recovered solvent can facilitate a more-objective assessment of SAP field tests and enable economic evaluation of SAP application to a commercial scale.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Steam-solvent combination methods (1.00)
- (2 more...)
Summary Air-injection-based recovery processes are receiving increased interest because of their high recovery potentials and applicability to a wide range of reservoirs. However, most operators require a certain level of confidence in the potential recovery from these (or any) processes before committing resources, which can be achieved with the use of numerical reservoir simulation. In a previous paper, (Gutiérrez et al. 2009) it was proposed that after successful laboratory testing, analytical calculations and semiquantitative simulation models would be used for pilot design and further optimization of the actual operation. However, the specific steps for building the field-scale-simulation models were not addressed explicitly. This paper discusses a detailed workflow that can be followed to engineer an air-injection project using thermal reservoir simulation. The first step of the simulation study involves the selection of a kinetic model that either can be developed specifically for the reservoir in question or taken from public literature. Second, the oil would be characterized in terms of the same pseudocomponents employed by the kinetic model, and relevant pressure/volume/temperature (PVT) data would be matched to develop a fluid model for the thermal simulator. This new fluid model is used in the field-scale-simulation model to history match the production history (i.e., before air injection) of the field. Third, relevant combustion-tube tests would be history matched to validate the kinetic model and refine the thermal data that would be entered into the field-scale model. Finally, the results and knowledge gained from the combustion-tube match(es) are applied to the field-scale model with the proper upscaling of some parameters. This simulation model would aid in selecting optimum well locations and operating strategies of the pilot. It would then be refined as the actual operation progresses to enhance its predictability and allow further optimization of the project. Technical considerations, advantages, and limitations of each step of the workflow are discussed in detail. This paper also presents workflow variations and recommendations applicable to new and already-mature air-injection projects for which simulation models are being developed.
- North America > United States (1.00)
- Europe (1.00)
- South America (0.92)
- (2 more...)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.96)
- Geology > Geological Subdiscipline (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- South America > Argentina > Mendoza > Cuyana Basin > Barrancas Field (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- Europe > Russia > Volga Federal District > Tatarstan > Volga Urals Basin > Mordovo Karmalskoye Field (0.99)
- (4 more...)
Summary In-situ extraction of ultraviscous deposits from the vast bitumen resources in western Alberta, Canada, requires significant water and energy usage, which consequently leads to greenhouse-gas emissions. Currently proven steam-based recovery schemes include cyclic-steam-stimulation (CSS), steamflooding, and steam-assisted gravity-drainage (SAGD) processes, which are accompanied by many economic and environmental challenges. Coinjection of solvent with steam is a technology that has the potential to improve the efficiency of steam processes as well as reduce energy usage and carbon dioxide emissions. In recent years, researchers and industry professionals have attempted to develop the process further by conducting fundamental research as well as field pilot trials, with varying degrees of success. However, the current level of understanding of the process and the knowledge surrounding the fundamental physics and mechanisms involved are not entirely satisfactory. In this paper, a parametric simulation study was performed to address the key aspects of the solvent-coinjection (SCI) process that contribute to further understanding and development of the process. Simulation observations were verified with experimental evidence where available to support the results and conclusions. Effects of several operational and geological parameters were evaluated on the performance of the SCI process, and the relative performance benefits were assessed over normal SAGD operations. These parameters included solvent type, solvent concentration, initial-solution gas/oil ratio (GOR), relative permeability curves, and pay thickness. The results revealed that the optimal solvent should not be chosen only on the basis of mobility-improvement capability, but also under consideration of other operational, phase- and flow-behavioral and/or geological conditions that are set or present. Higher concentrations of solvents showed more energy-saving upsides than rate-acceleration benefits. It was also observed that the reservoir steam-intake rate is still likely to be the prime performance indicator of the SCI process. In addition, SCI showed that the potential exists for accessing more resources, particularly below the producer level. Furthermore, steam trap control on the producer seems to be problematic when used for SCI simulation. With the current well-control capacity of simulators, a higher degree of subcool is likely to be needed to avoid live vapor-phase production from the producer.
- North America > Canada > Alberta (0.67)
- Europe > United Kingdom > North Sea > Central North Sea (0.24)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Firebag Oil Sands Project > Wabiskaw-McMurray Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Leismer Oil Sands Project (0.98)
Summary Foamy-oil viscosity is a controversial topic among researchers regarding what happens to the oil viscosity when the solution gas starts coming out of solution because of decreasing pressure and the released gas starts migrating with the oil in the form of dispersed gas bubbles. For conventional oils, below the true bubblepoint pressure, the oil viscosity increases as the gas freely evolves from the oil. For foamy oils, it has been suggested that the apparent oil viscosity remains relatively constant or perhaps declines slightly between the true bubblepoint and a characteristic lower pressure, called pseudobubblepoint, which is the pressure at which the gas starts separating from the oil. Below this pressure, the viscosity increases, reaching the dead-oil value at atmospheric pressure. However, it is a well-known fact in dispersion rheology that the viscosity of dispersion is higher than the viscosity of the continuous phase. Therefore, the concept of foamy-oil viscosity being lower than the oil viscosity is counterintuitive. It is likely that the apparent viscosity for flow of foamy oil in porous media is not the true dispersion viscosity because of the size of dispersed bubbles being comparable to the pore sizes. This study investigates this issue by measuring the foamy-oil viscosity under varied conditions. The effect of several parameters, such as flow rate, gas volume fraction, and type of viscometer employed, on foamy-oil viscosity was evaluated experimentally. Three different viscosity-measurement techniques, including Cambridge falling-needle viscometer, capillary tube, and a slimtube packed with sand, were used to measure the apparent viscosity of gas-in-oil dispersions. The results show that the type of measuring device used has a significant effect. The results obtained with Cambridge falling-needle viscometer correlate better with the observed behaviour in the sand-packed slimtube than the capillary viscometer results. Overall, the apparent viscosity of foamy oil was found to be similar to live-oil viscosity for a range of gas volume fractions.
- North America > United States (1.00)
- North America > Canada > Alberta (0.49)
- Research Report > New Finding (0.66)
- Research Report > Experimental Study (0.48)