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Collaborating Authors
Results
New Paradigm in the Understanding of In Situ Combustion: The Nature of the Fuel and the Important Role of Vapor Phase Combustion
Gutiérrez, Dubert (AnBound Energy Inc.) | Mallory, Don (University of Calgary) | Moore, Gord (University of Calgary) | Mehta, Raj (University of Calgary) | Ursenbach, Matt (University of Calgary) | Bernal, Andrea (AnBound Energy Inc.)
Abstract Historically, the air injection literature has stated that the main fuel for the in situ combustion (ISC) process is the carbon-rich, solid-like residue resulting from distillation, oxidation, and thermal cracking of the residual oil near the combustion front, commonly referred to as "coke". At first glance, that assumption may appear sound, since many combustion tube tests reveal a "coke bank" at the point of termination of the combustion front. However, when one examines both the laboratory results from tests conducted on various oils at reservoir conditions, and historical field data from different sources, the conclusion may be different than what has been assumed. For instance, combustion tube tests performed on light oils rarely display any significant sign of coke deposition, which would make them poor candidates for air injection; nevertheless, they have been some of the most successful ISC projects. It is proposed that the main fuel consumed by the ISC process may not be the solid-like residue, but light hydrocarbon fractions that experience combustion reactions in the gas phase. This vapor fuel forms as a result of oxidative and thermal cracking of the original and oxidized oil fractions. An analysis of different oxidation experiments performed on oil samples ranging from 6.5 to 38.8°API, at reservoir pressures, indicates that this behavior is consistent across this wide density spectrum, even in the absence of coke. While coke will form as a result of the low temperature oxidation of heavy oil fractions, and while thermal cracking of those fractions on the pathway to coke may produce vapor components which may themselves burn, the coke itself is not likely the main fuel for the process, particularly for lighter oils. This paper presents a new theory regarding the nature and formation of the main fuel utilized by the ISC process. It discusses the fundamental concepts associated with the proposed theory, and it summarizes the experimental laboratory evidence and the field evidence which support the concept. This new theory does still share much common ground with the current understanding of the ISC process, but with a twist. The new insights result from the analysis of laboratory tests performed on lighter oils at reservoir pressures; data which was not available at the time that the original ISC concepts were developed. This material suggests a complete change to one of the most important paradigms related to the ISC process, which is the nature and source of the fuel. This affects the way we understand the process, but provides a unified and consistent theory, which is important for the modelling efforts and overall development of a technology that has the potential to unlock many reserves from conventional and unconventional reservoirs.
- North America > United States (1.00)
- Europe (1.00)
- North America > Canada > Alberta (0.94)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.90)
- Geology > Geological Subdiscipline (0.67)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.94)
- North America > United States > Nebraska > Sloss Field (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > United States > South Dakota > Williston Basin > Buffalo Field > Red River Formation (0.94)
- North America > United States > North Dakota > Medicine Pole Hills Field (0.94)
Lab and Pilot-Scale Evaluation of Stable Foam for Drilling in High Temperature Environment
Griffith, Christopher (Chevron) | Linnemeyer, Harry (Chevron) | Kim, Do Hoon (Chevron) | Hahn, Ruth (Chevron) | Zhou, Jimin (Chevron) | Upchurch, Eric (Chevron) | Malik, Taimur (Chevron) | Wileman, Angel (Southwest Research Institute) | Beck, Griffin (Southwest Research Institute) | Bhagwat, Swanand (Southwest Research Institute) | Gutierrez, Luis (Southwest Research Institute)
Abstract Using foams to drill in low pore pressure reservoirs is attractive because of their low density, high viscosity, and ability to transport cuttings. However, in high temperature reservoirs (240 °F) with H2S gas present, there are concerns with the long-term stability of a foam drilling fluid. In this work, we highlight a lab program to develop a stable drilling foam for drilling in a low pore pressure, high temperature reservoir. The work also includes pilot-scale experiments to evaluate foam performance. Aqueous nitrogen-in-water foams were stabilized with a preferred foaming surfactant formulation, and the rheology and stability of the foams were measured at representative drilling conditions (temperature and pressure) at the lab and pilot-scale. The foams were also evaluated for their compatibility with current drilling fluids used on site and for stability in the presence of H2S gas (at 1900 psi and 140 °F). The drilling foam was also evaluated using a pilot-scale flow loop comprised of a rheology flow loop and a model drilling wellbore. The experiments included measuring the foam rheology, foam stability in the model wellbore, and gas migration tests to understand how the foam suppresses upwardly migrating gas bubbles. We successfully developed a surfactant stabilized foam designed for a high-temperature reservoir with H2S gas present. We found that H2S can negatively impact foam stability if proper surfactants are not selected. Our foam showed less than 10% liquid drainage after 12 hours at 240 °F and showed no significant degradation upon contact with 17 mol% H2S gas. Additionally, the foam was compatible with all drilling fluids (both water-based and oil-based) currently used at the drill site and demonstrated good stability in a model pilot-scale drilling wellbore. Interestingly, when the wellbore was angled at 30 degrees from vertical with the eccentric drill pipe rotating at 100 RPM, the foams were susceptible to degradation compared to an equivalent scenario of a vertical wellbore with concentric rotating drill pipe. The gas migration tests at the pilot-scale showed the foam was capable of significantly slowing down an upwardly moving gas bubble with and without pipe rotation.
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management (1.00)
- Well Drilling > Drillstring Design (1.00)
- (4 more...)
An Experimental Investigation of Polymer Mechanical Degradation at cm and m Scale
Åsen, Siv Marie (UiS, IRIS and The National IOR Centre of Norway) | Stavland, Arne (IRIS and The National IOR Centre of Norway) | Strand, Daniel (IRIS and The National IOR Centre of Norway) | Hiorth, Aksel (UiS, IRIS and The National IOR Centre of Norway)
Abstract In this work, we challenge the common understanding that mechanical degradation takes place at the rock surface or within the first few mm. The effect of core length on mechanical degradation of synthetic EOR polymers was investigated. We constructed a novel experimental set-up for studying mechanical degradation at different flow rates as a function of distances travelled. The set-up enabled us to evaluate degradation in serial mounted core segments of 3, 5, 8 and 13 cm individually or combined. By recycling we could also evaluate degradation at effective distances up to 20 m. By low rate reinjecting of polymers previously degraded at higher rates, we simulated the effect of radial flow on degradation. Experiments were performed with two different polymers (high molecular weight HPAM and low molecular weight ATBS) in two different brines (0.5% NaCl and synthetic seawater). In linear flow at high shear rates, we observed a decline in degradation rate with distance travelled, but a plateau was not observed. Even after 20 m there was still some degradation taking place. The molecular weight (MW) of the degraded polymer could be matched with a power law dependency, MWD ~L, where x for the HPAM was 0.07 and x for ATBS was 0.03. We conclude that in linear flow, the mechanical degradation depends on the core length. However, in radial flow where the velocity decreases by length, the mechanical degradation reaches equilibrium with no further degradation deeper into the formation. For the experiments where we evaluated degradation over large distances at high shear rates, we observed a decline in degradation rate with distance travelled, but we could not conclude that we reached a plateau. Even after 20 m there is still some degradation taking place. It is important to consider this knowledge when interpreting core scale experiments. However, the observed degradation is associated with high-pressure gradients, in the order of 100 bar/meter, which at field scale is not realistic. We confirmed previous findings; degradation depends on salinity and molecular weight. Results show that in all experiments with significant degradation, most of the degradation takes place in the first core segment. Moreover, the higher the shear rate and degradation, the higher is the fraction of degradation that occurs in the first core segment.
- Europe (1.00)
- North America > United States (0.46)
Experimental and Theoretical Study of Operating Pressure and Capillary Pressure on Vapor Oil Gravity Drainage VOGD in Fractured Reservoirs
Tang, B.. (The University of Texas At Austin) | Anand, N.. (The University of Texas At Austin) | Nguyen, B.. (The University of Texas At Austin) | Sie, C.. (The University of Texas At Austin) | Verlaan, M.. (Shell) | Díaz, O. Castellanos (Canadian Natural Resources Ltd.) | Nguyen, Q. P. (The University of Texas At Austin)
Abstract The Vapor-Oil Gravity Drainage (VOGD) is a low temperature, solvent-enhanced gas-oil gravity drainage (GOGD) process targeting naturally fractured viscous reservoirs. The experimental set up and corresponding acquired data was previously introduced by the authors (Anand et al., 2017) in which the effects of temperature, solvent injection rate, and solvent type (n-Butane and dichloromethane (DCM)) were investigated. Results from Anand et al. work indicated encouraging high oil rates and ultimate recoveries; results also demonstrated that the oil rates and recovery were impacted by diffusion and dispersion (in the form of intrinsic gas rate), asphaltene precipitation, and capillary pressure. The intent of this work is to further study the mechanisms behind VOGD; in particular those related to operating pressure and solvent vapor-oil capillary pressure. The results from this work show that the ultimate recovery and oil rate are positively correlated to the operating pressure; experiments conducted at 50% and 75% saturation pressure (Psat) yielded lower ultimate oil recoveries, ranging from 33% to 68% of original oil in place (OOIP), when compared to the experiments conducted at 90% Psat (70% of OOIP). Moreover, n-butane performed better than DCM and lesser asphaltene precipitation was seen at lower Psat. The main drivers for these observations were found to be lower solvent solubility and larger capillary pressure values at lower values of Psat.
- 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 > Reserves Evaluation > Estimates of resource in place (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Steam-solvent combination methods (1.00)
- (6 more...)