Oxidation kinetic experiments with various crude oil types show two reaction peaks at about 250°C (482°F) and 400°C (725°F). These experiments lead to the conclusion that the fuel during high temperature oxidation is an oxygenated hydrocarbon. A new oxidation reaction model has been developed which includes two partiallyoverlapping reactions: namely, low-temperature oxidation followed by high-temperature oxidation. For the fuel oxidation reaction, the new model includes the effects of sand grain size and the atomic hydrogen-carbon (H/C) and oxygen-carbon (O/C) ratios of the fuel. Results based on the new model are in good agreement with the experimental data. Methods have been developed to calculate the atomic H/C and O/C ratios. These methods consider the oxygen in the oxygenated fuel, and enable a direct comparison of the atomic H/C ratios obtained from kinetic and combustion tube experiments. The finding that the fuel in kinetic tube experiments is an oxygenated hydrocarbon indicates that oxidation reactions are different in kinetic and combustion tube experiments. A new experimental technique or method of analysis will be required to obtain kinetic parameters for oxidation reactions encountered in combustion tube experiments and field operations,
Experimental, analytical, and simulation studies have been conducted to evaluate the feasibility of sequestering supercritical CO 2 in depleted gas reservoirs. The experimental runs involved the following steps. First, the 1 ft long by 1 in. diameter carbonate core is inserted into a viton Hassler sleeve and placed inside an aluminum coreholder that is then evacuated. Second, with or without connate water, the carbonate core is saturated with methane. Third, supercritical CO 2 is injected into the core with 300 psi overburden pressure. From the volume and composition of the produced gas measured by a wet test meter and a gas chromatograph, the recovery of methane at CO 2 breakthrough is determined. The core is scanned three times during an experimental run to determine core porosity and fluid saturation profile: at start of the run, at CO 2 breakthrough, and at the end of the run. Runs were made with various temperatures, 20°C (68°F) to 80°C (176°F), while the cell pressure is varied, from 500 psig (3.55 MPa) to 3000 psig (20.79 MPa) for each temperature.An analytical study of the experimental results has been also conducted to determine
Summary Coinjecting solvent with steam under a steam-assisted-gravity-drainage (SAGD) process to reduce the required steam for production has gained importance in recent years. An extensive 2D simulation study to better understand the drainage mechanism of steam-with-solvent coinjection in the SAGD process shows that the condensation time difference of solvent and steam results in different films of gas solvent, liquid solvent, and water along the fluid interface. There is an optimal solvent-type and -concentration-ratio range for a particular reservoir and operating condition. Coinjecting the solvent at low concentration ratios can take advantage of the solvent dilution effect without losing too much heat effect from steam. In addition, this study indicates coinjection of suitable solvent mixtures may lead to better performance than injection of pure solvent in the field.
Experimental, analytical, and simulation studies have been conducted to evaluate the feasibility of sequestering supercritical CO 2 in depleted gas reservoirs. The experimental runs involved the following steps. First, the 1 ft long by 1 in. diameter carbonate core is inserted into a viton Hassler sleeve and placed inside an aluminum coreholder that is then evacuated. Second, with or without connate water, the carbonate core is saturated with methane. Third, supercritical CO 2 is injected into the core with 300 psi overburden pressure. From the volume and composition of the produced gas measured by a wet test meter and a gas chromatograph, the recovery of methane at CO 2 breakthrough is determined. The core is scanned three times during an experimental run to determine core porosity and fluid saturation profile: at start of the run, at CO 2 breakthrough, and at the end of the run. Runs were made with various temperatures, 20°C (68°F) to 80°C (176°F), while the cell pressure is varied, from 500 psig (3.55 MPa) to 3000 psig (20.79 MPa) for each temperature.An analytical study of the experimental results has been also conducted to determine iv the dispersion coefficient of CO 2 using the convection-dispersion equation. The dispersion coefficient of CO 2 in methane is found to be relatively low, 0.01-0.3 cm 2 /min.Based on experimental and analytical results, a 3D simulation model of one eighth of a 5-spot pattern was constructed to evaluate injection of supercritical CO 2 under typical field conditions. The depleted gas reservoir is repressurized by CO 2 injection from 500 psi to its initial pressure 3,045 psi. Simulation results for 400 bbl/d CO 2 injection may be summarized as follows. First, a large amount of CO 2 is sequestered: (i) about 1.2 million tons in 29 years (0 % initial water saturation) to 0.78 million tons in 19 years (35 % initial water saturation) for 40-acre pattern, (ii) about 4.8 million tons in 112 years (0 % initial water saturation) to 3.1 million tons in 73 years (35 % initial water saturation) for 80-acre pattern. Second, a significant amount of natural gas is also produced: (i) about 1.2 BSCF or 74 % remaining GIP (0 % initial water saturation) to 0.78 BSCF or 66 % remaining GIP (35 % initial water saturation) for 40-acre pattern, (ii) about 4.5 BSCF or 64 % remaining GIP (0 % initial water saturation) to 2.97 BSCF or 62 % remaining GIP (35 % initial water saturation) for 80-acre pattern. This produced gas revenue could help defray the cost of CO 2 sequestration. In short, CO 2 sequestration in depleted gas reservoirs appears to be a win-win technology. v DEDICATION My graduate studies at Texas A&M University would not have been possible without the support and understanding of my wife and son. This dissertation is dedicated to: my wife, Eunsun Lee, my son: Eric Hyobin Seo, and to my parents, my father Soobeom Seo, my mother Dongsil Cho, and my grandmother for their support, love, prayer, and guidance. vi ACKNOWLEDGEMENTS I would like to express my deepest appreciation to my research advis...
Coinjecting solvent with steam under steam-assisted gravitydrainage (SAGD) process to reduce the required steam amount for heavy-oil production has gained importance in recent years. The objective of this experimental study was to investigate the drainage mechanism of coinjecting light and heavy solvents to improve production performance.A 2D cross-sectional low-pressure scaled physical model was constructed. The model represented a half-symmetry cross section of a typical SAGD drainage in the Athabasca formation. Using an infrared camera, we visualized and recorded expansion of the steam chamber and temperature distribution. The fluid injection rate, pressure, and temperature, and produced-liquid volumes were also recorded.The results show that the relative condensation time of solvent and steam results in different production performances. Light solvent, delivered in the vapour phase to the entire fluid interface, reduces the bitumen viscosity along the whole vapour-chamber boundary, but it may build a thick gas blanket that may reduce the heat transfer from the high-temperature vapour chamber to the surrounding low-temperature bitumen. Coinjecting a suitable multicomponent-solvent mixture, including a heavy solvent, can enhance the production performance by altering the condensation dynamics of the light hydrocarbons.The conclusions from this study can be used to design suitable solvent mixtures and coinjection strategies to deliver a higher production rate, higher recovery factor with lower cumulative steam required/oil ratio (CSOR), and lower cumulative energy required for oil production (CEOR) from SAGD performance.
A depleted natural gas reservoir can store significantly more gas than a depleted oil reservoir (with the same initial hydrocarbon pore volume) for two reasons. First, ultimate gas recovery (about 65% of gas initially-in-place) is typically about twice that of oil (average 35% of oil initially-in-place). Second, gas is some 30 times more compressible than oil or water. CO2 has a critical temperature of 31°C (88°F) and a critical pressure of 7.38 MPa (1070 psia). Consequently, at pressures and temperatures typically encountered in the field, carbon dioxide will behave as a supercritical fluid. However, displacement of natural gas by supercritical CO2 has not been done in the field and is not well understood. As part of a CO2 sequestration study, we have conducted experimental and analytical studies to evaluate the feasibility of displacing natural gas with supercritical CO2. The experiments involved injecting supercritical CO2 into an aluminum Hassler core-holder containing a 1-ft long by 1-in. diameter carbonate core initially saturated with methane. Rate and composition of the produced gas were measured, enabling determination of mole fraction of produced CO2 as a function of time. In addition, the core holder was CT scanned to determine core porosity, and CO2 and methane saturation. Experiments have been conducted for core pressures in the range, 500–3000 psig at 70°–140°F. Results indicate that some 73%–87% of the gas initially-in-place is recovered at CO2 breakthrough, with a low CO2 dispersion coefficient of 0.01–0.12 cm2/min. We can tentatively conclude that CO2 injection into depleted or abandoned gas reservoirs would not only sequester CO2 but would also re-pressurize the reservoir, and most likely result in effective displacement of the gas. Thus, production of hitherto unrecoverable gas reserves could help defray the cost of CO2 sequestration: in short, a possible win-win technology. Introduction In 1996 the Norwegian state oil company, Statoil, started the first large-scale underground disposal of CO2 in the North Sea.1,2 Some 1 million tonnes per year of CO2 - separated out of the natural gas produced from the Sleipner Vest field - has been injected into the overlying Utsira aquifer. A similar project is being planned for the Natuna gas field in Indonesia. The field contains some 1.4×106 m3 (50 TSCF) gas, about 70% by volume of which is carbon dioxide. The Natuna project, to be undertaken by a consortium of companies, would involve liquefying the sales gas (LNG) while the carbon dioxide would be injected into an aquifer. Underground disposal of CO2 - emitted by industrial sources such as fossil fuel-fired power plants - has not been undertaken. In the last decade, however, there has been worldwide concern on possible global warming caused by heat being trapped by CO2 in the upper atmosphere (the green-house effect). In 1993, the European Commission began the Joule II Non-nuclear Energy Research Program, which studied sequestration of industrially produced CO2.2,3 The Joule II study concluded that (i) shallow reservoirs do not provide sufficient storage for carbon dioxide because it would be in gaseous form, (ii) for maximum storage capacity, carbon dioxide has to be stored as a supercritical fluid - which requires reservoirs deeper than 800 m (2,600 ft), (iii) such deep reservoirs could be depleted oil or gas reservoirs or structures containing aquifers, (iv) if carbon dioxide is stored in aquifers, then to avoid contaminating shallower potable water sources, carbon dioxide would be sequestered in aquifers deep below the North Sea, (v) if carbon dioxide is injected into a limestone reservoir, carbonate dissolution could occur around the injection wells causing subsidence, and (vi) the cost of carbon dioxide separation out of flue gas is significantly higher than that of transporting and injecting carbon dioxide in reservoirs.
Steam Assisted gravity drainage (SAGD) is demonstrated as a proven technology to unlock heavy oil and bitumen in Canadian reservoirs. One of the long-term concerns with the SAGD process is high energy intensity and related environmental impacts. The addition of suitable hydrocarbon solvents to steam has long been regarded as the simplest and most effective method to increase SAGD performance. Higher oil recovery, accelerated oil production rate, reduced steam to oil ratio and generally more favorable economics is expected from the addition of potential hydrocarbon additives to steam. This paper summarizes experimental results of addition of potential solvents to steam in SAGD process. N-Hexane and n-heptane were co-injected with the steam and the experimental results were compared with pure steam injection. In addition, pure heated n-hexane was injected in one experiment to assess the performance of solvent-based processes. Experiments were conducted using a scaled two-dimensional physical model. Peace River Bitumen samples were used to conduct the experiments at 80 psia. Experimental results were analyzed to determine the key variables involved in Solvent Assisted SAGD (SA-SAGD) processes. Solvent choice is not solely dependent on mobility improvement capability but also reservoir properties and operational conditions. Co-injection of suitable solvents with the steam led to accelerated oil production rate, higher oil recovery and lower energy to oil ratio. Solvent requirement for pure heated n-hexane injection was considerably high. The vaporized solvent chamber expansion was slow due to low heat content of the solvent and heat losses.
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