Yaser Souraki

Experimental PVT Property Analyses for Athabasca Bitumen

Heavy oil and tar sands are important hydrocarbon resources that are destined to play an increasingly important role in the oil supply of the world. A huge proportion of total world oil resources are in the form of these highly viscous fluids. The main recovery mechanism for these kinds of reservoirs is to somehow reduce their viscosity by the application of heat. In these extra heavy oil reservoirs, the reservoir has almost no injectivity, and therefore conventional steam flooding is hard to conduct. Steam Assisted Gravity Drainage (SAGD), however, reduces the viscosity of bitumen in place and the heated bitumen drains due to gravity forces towards the production well, where it is produced. Modeling and evaluating the production mechanisms in this process requires a thorough understanding of multi-phase flow parameters like relative permeability.Relative permeability data depend on a number of different parameters among others temperature and fluid viscosity. Viscosities of the flowing fluids drop with temperature, which can affect the relative permeability data. There has been a long debate on the actual impact of temperature on the relative permeabilities. Although some authors have reported saturation range shifts and relative permeability curve variations by temperature, others have attributed these variations to artifacts inherent in the methods used and the systems tested. Viscous instabilities and fingering issues have been blamed for temperature dependencies reported, and some researchers have reported that relative permeability data changes due to oil/water viscosity ratio changes at different temperatures.The variations in the experimental conditions have resulted in different and even contradictory results. There is specifically few experimental works conducted on Athabasca oil systems, and previously reported trends mainly apply to less viscous oils. This implies that the actual effect of temperature on flow behavior of fluids in the rock is case specific. Due to the contradictory reports and conclusions, which are due to variation in the systems being tested, it seemed necessary to conduct our own core flooding experiments, and investigate the curves of relative permeability. The objective was to obtain the imbibition relative permeability curves in an Athabasca oil type reservoir at different temperatures and oil viscosities, and figure out any possible trends of variations with temperature.Before conducting the core flooding experiments, some fluid behavior experiments were done to figure out the properties of bitumen used in this study. These include fluid compositions, density, viscosity, molecular weight and oil/steam interfacial tension. These properties were further used in numerical simulation studies.Core floodings were conducted on glass bead packs and sand packs saturated with heavy oils with varying viscosities. Displacement experiments with water were performed at different temperatures, and unsteady-state method of relative permeability measurement was conducted. The relative permeability data were determined by history matching the oil production data and pressure differential data in each experiment.Results indicated a change in the water saturation range in the oil-water relative permeability curves. The shift was towards higher water saturations, meaning an increase in irreducible water saturation and a decrease in residual oil saturation. Regarding the shape of relative permeability data, no unique trend of either rising or falling with temperature was found for oil and water relative permeability curves. The viscous instabilities are believed to be present in the experiments.As the same saturation range shift occurs by comparing the results at the same temperature level and by only changing the oil viscosity, this suggests that the temperature dependency of relative permeabilities can be attributed to the drop in oil to water viscosity ratio by temperature.The variations of relative permeability data with temperature was therefore found to be more related to artifacts in the experimental procedures like viscous fingering, and fluid viscosity changes than fundamental flow properties.Numerical simulations were accomplished on field scale SAGD and ES-SAGD (Expanding Solvent SAGD) operations testing the effect of relative permeability curves. Temperature dependent relative permeability data were tested and Oil production was found to be strongly dependant on the end point data. It is therefore suggested to use this option as a matching criterion when trying to history match SAGD field data.Since the main experimental part of this study deals with temperature dependency of relative permeability data, the introduction of this thesis is totally devoted to introducing this concept and its measurement methods and a literature review on the works performed so far. The main thesis is composed of three main parts, the fluid behavior experiments on bitumen, one-dimensional flow studies and multi-dimensional flow part. The results of fluid behavior experiments are given in chapter 2. Chapters 3 and 4 are devoted to one-dimensional flow works and chapters 5 and 6 present the part of this thesis dealing with two and three-dimensional flow. It should, however, be mentioned that chapters 4 to 6 can be read independently, as the contents of these chapters are taken from previously published papers with some minor revisions.

Experimental Investigation of Decalin and Metal Nanoparticles-Assisted Bitumen Upgrading During Catalytic Aquathermolysis

Unconventional oil reservoirs such as heavy oil, extra heavy oil, oil shale and oil sand/bitumen are very interesting since these kinds of oil are currently proven to constitute a huge amount of total world oil reserves. However, it is difficult to handle these kinds of oil due to very high viscosity. Thermal application methods may have great possibilities for heavy oil and bitumen production. Prior to shipment to downstream markets, the bitumen needs to be upgraded to produce higher value of liquid hydrocarbon products. However, the issues in oil sands industry are environmental challenges such as green-house-gas (ghg) emission, huge amount of fuel and water consumption, liquid and solid wastes disposal. The objective of this study is to investigate an effective and efficient upgrading process by adding decalin as hydrogen donor, water and various type nanometal particles (40-500 nm) as catalysts into Athabasca bitumen. Athabasca bitumen has been successfully upgraded by reducing its viscosity about 80% (measured at 60 oC) by applying catalytic aquathermolysis at 240 oC during 12 hours. As hydrogen donor, decalin is very interesting. Besides cheap, it could dramatically accelerate viscosity reduction with concentration of 5 wt.%. The degree of viscosity reduction will increase with increased decalin concentration. However degree of bitumen upgrading will decrease with presence of water. It seems that synergetic effects to the upgrading process did not work effectively. Hence water consumption during aquathermolysis process might be reduced to minimize the cost. Since earlier studies have shown that nanoparticles may reduce heavy oil viscosity, four types of nanometal particles have been studied and some of them accelerated viscosity reduction during catalytic aquathermolysis process at particular concentration. Improper nanometal particle type and concentration are reversed effect. Temperature and heating time have vital role in the upgrading process.

Investigating the Temperature Dependency of Oil and Water Relative Permeabilities for Heavy Oil Systems

A look into the literature on the temperature dependency of oil and water relative permeabilities reveals contradictory reports. There are some publications reporting shifts in the water saturation range as well as variations in the relative permeability curves by temperature. On the other hand, some authors have blamed the experimental artifacts, viscous instabilities and fingering issues for these variations. We have performed core flooding experiments to further investigate this issue. Glass bead packs and sand packs were used as the porous media, and Athabasca bitumen with varying viscosities was displaced by hot water at differing temperatures. The unsteady-state method of relative permeability measurement was applied and the experimental data were history matched by a simulator that is tailor made to predict the relative permeabilities. The matches were obtained by varying the relative permeability correlation parameters. The results indicated that the initial water saturation has a direct relation with temperature, while residual oil saturation generally drops at higher temperatures. Although the water saturation range shifts, no direct and unique trend for either oil or water relative permeability is justified. The spread in relative permeabilities especially in the case of higher permeable cores suggests that viscous instabilities are present. As the same saturation shift happens by only changing the oil viscosity, the relative permeability variations with temperature can be attributed to oil to water viscosity ratio changes with temperature. Temperature dependency of relative permeabilities is more related to experimental artifacts, viscous fingering and viscosity changes than fundamental flow properties.

Experimental and Numerical Study of Steam Flooding in Fractured Porous Media

Heavy oil and tar sands are important hydrocarbon resources that are destined to play an increasingly important role in the oil supply of the world. A huge proportion of total world oil resources are in the form of these highly viscous fluids. The main recovery mechanism for these kinds of reservoirs is to somehow reduce their viscosity by the application of heat. In these extra heavy oil reservoirs, the reservoir has almost no injectivity, and therefore conventional steam flooding is hard to conduct. Steam Assisted Gravity Drainage (SAGD), however, reduces the viscosity of bitumen in place and the heated bitumen drains due to gravity forces towards the production well, where it is produced. Modeling and evaluating the production mechanisms in this process requires a thorough understanding of multi-phase flow parameters like relative permeability.Relative permeability data depend on a number of different parameters among others temperature and fluid viscosity. Viscosities of the flowing fluids drop with temperature, which can affect the relative permeability data. There has been a long debate on the actual impact of temperature on the relative permeabilities. Although some authors have reported saturation range shifts and relative permeability curve variations by temperature, others have attributed these variations to artifacts inherent in the methods used and the systems tested. Viscous instabilities and fingering issues have been blamed for temperature dependencies reported, and some researchers have reported that relative permeability data changes due to oil/water viscosity ratio changes at different temperatures.The variations in the experimental conditions have resulted in different and even contradictory results. There is specifically few experimental works conducted on Athabasca oil systems, and previously reported trends mainly apply to less viscous oils. This implies that the actual effect of temperature on flow behavior of fluids in the rock is case specific. Due to the contradictory reports and conclusions, which are due to variation in the systems being tested, it seemed necessary to conduct our own core flooding experiments, and investigate the curves of relative permeability. The objective was to obtain the imbibition relative permeability curves in an Athabasca oil type reservoir at different temperatures and oil viscosities, and figure out any possible trends of variations with temperature.Before conducting the core flooding experiments, some fluid behavior experiments were done to figure out the properties of bitumen used in this study. These include fluid compositions, density, viscosity, molecular weight and oil/steam interfacial tension. These properties were further used in numerical simulation studies.Core floodings were conducted on glass bead packs and sand packs saturated with heavy oils with varying viscosities. Displacement experiments with water were performed at different temperatures, and unsteady-state method of relative permeability measurement was conducted. The relative permeability data were determined by history matching the oil production data and pressure differential data in each experiment.Results indicated a change in the water saturation range in the oil-water relative permeability curves. The shift was towards higher water saturations, meaning an increase in irreducible water saturation and a decrease in residual oil saturation. Regarding the shape of relative permeability data, no unique trend of either rising or falling with temperature was found for oil and water relative permeability curves. The viscous instabilities are believed to be present in the experiments.As the same saturation range shift occurs by comparing the results at the same temperature level and by only changing the oil viscosity, this suggests that the temperature dependency of relative permeabilities can be attributed to the drop in oil to water viscosity ratio by temperature.The variations of relative permeability data with temperature was therefore found to be more related to artifacts in the experimental procedures like viscous fingering, and fluid viscosity changes than fundamental flow properties.Numerical simulations were accomplished on field scale SAGD and ES-SAGD (Expanding Solvent SAGD) operations testing the effect of relative permeability curves. Temperature dependent relative permeability data were tested and Oil production was found to be strongly dependant on the end point data. It is therefore suggested to use this option as a matching criterion when trying to history match SAGD field data.Since the main experimental part of this study deals with temperature dependency of relative permeability data, the introduction of this thesis is totally devoted to introducing this concept and its measurement methods and a literature review on the works performed so far. The main thesis is composed of three main parts, the fluid behavior experiments on bitumen, one-dimensional flow studies and multi-dimensional flow part. The results of fluid behavior experiments are given in chapter 2. Chapters 3 and 4 are devoted to one-dimensional flow works and chapters 5 and 6 present the part of this thesis dealing with two and three-dimensional flow. It should, however, be mentioned that chapters 4 to 6 can be read independently, as the contents of these chapters are taken from previously published papers with some minor revisions.

Experimental and Numerical Investigation of Steam Flooding in Heterogeneous Porous Media Containing Heavy Oil

Experimental and numerical investigation of steam flooding in heterogeneous porous media containing heavy oil

Wettability alteration of carbonate reservoir rock using amphoteric and cationic surfactants: Experimental investigation

ABSTRACT The objective of this study is to prove that altering the wettability of reservoir rocks by two surfactants (hexadecyl amino benzene sulfonic acid [HABSA] and cationic hexa decyl trimethyl ammonum bromide [CTAB]). Changing the wettability to preferentially water-wet condition will reduce the residual oil saturation (Sor). Because of reducing Sor, the percentage of recovered oil is increased. All surfactants were tested for their ability to alter the wettability of reservoir rocks. This alteration was measured based on the contact angle methods. Results of this study show that both amphoteric HABSA and CTAB surfactants alter the wettability of carbonate rocks from oil-wet to water-wet, while CTAB alters the wettability from oil-wet to water-wet more than HABSA. Also, recovery factor in CTAB injection was more than HABSA injection. Ultimately, the results show that the CTAB surfactant is more effective than HABSA surfactant to alter the wettability and improve oil recovery from carbonate reservoirs.

Experimental Investigation and Comparison of Thermal Processes: SAGD, ES-SAGD and SAS

− Thermal processes such as cyclic steam stimulation (CSS), steam-assisted gravity drainage (SAGD), in-situ combustion and toe-to-heel air injection (THAI) are being applied widely to recover heavy oil and bitumen, deposited in different formations located worldwide, especially in Canada, Venezuela and United States. Among these processes, SAGD is known as the most prosperous and promising method applicable in Alberta sandstone heavy oil and bitumen reservoirs. However, existence of technical and environmental problems forced researchers to find solutions in order to mitigate deficiencies of SAGD process. Some of the main disadvantages of SAGD are: high consumption of water, waste water management and facility, high expenditures of fuel to generate steam and greenhouse-gas (GHG) emission. Also, it is not applicable in thin reservoirs because of heat and energy loss. Recently, hybrid processes were introduced to overcome the mentioned problems. Hybrid processes utilize the advantage of steam injection and solvent injection together or alternatively to reduce the viscosity of in-situ oil as much as possible. Some of these processes are: expanding-solvent SAGD (ESSAGD), steam alternating solvent (SAS), liquid addition to steam enhanced recovery (LASER), solvent-assisted SAGD (SA-SAGD) and solventaided process (SAP). The salient advantages of hybrid processes over SAGD are namely; lower consumption of water and energy, higher ultimate recovery factor, faster oil drainage rate and lower CO2 (GHG) emissions.SAGD, ES-SAGD and SAS processes were implemented in this work using cylindrical stainless steel core holder filled with glass beads and saturated with slightly upgraded Athabasca bitumen. First, performance of the mentioned processes was evaluated in terms of cumulative steam-oil ratio (CSOR), oil drainage rate, cumulative oil productionand ultimate recovery factor. SAS and ES-SAGD represented better results than SAGD process at the same conditions based on the aforementioned efficiency indicators. Thereupon, effect of steam injection rate on SAGD process and the impact of solvent injection rate and type on ESSAGD process were investigated. Results of the experiments elucidated that higher steam injection rate yields higher oil drainage rate and recovery factor while increases the CSOR of the SAGD process. Three types of solvent namely; n-pentane, nhexane and n-heptane were used to investigate the effect of solvent type on ES-SAGD performance. Among them n-pentane showed better outcomes, however, higher injection rate of n-hexane improved the process both in terms of CSOR and recovery factor.

Simulation Study of 2-D SAGD Experiment and Sensitivity Analysis of Laboratory Parameters

Heavy oil and tar sands are important hydrocarbon resources that are destined to play an increasingly important role in the oil supply of the world. A huge proportion of total world oil resources are in the form of these highly viscous fluids. The main recovery mechanism for these kinds of reservoirs is to somehow reduce their viscosity by the application of heat. In these extra heavy oil reservoirs, the reservoir has almost no injectivity, and therefore conventional steam flooding is hard to conduct. Steam Assisted Gravity Drainage (SAGD), however, reduces the viscosity of bitumen in place and the heated bitumen drains due to gravity forces towards the production well, where it is produced. Modeling and evaluating the production mechanisms in this process requires a thorough understanding of multi-phase flow parameters like relative permeability.Relative permeability data depend on a number of different parameters among others temperature and fluid viscosity. Viscosities of the flowing fluids drop with temperature, which can affect the relative permeability data. There has been a long debate on the actual impact of temperature on the relative permeabilities. Although some authors have reported saturation range shifts and relative permeability curve variations by temperature, others have attributed these variations to artifacts inherent in the methods used and the systems tested. Viscous instabilities and fingering issues have been blamed for temperature dependencies reported, and some researchers have reported that relative permeability data changes due to oil/water viscosity ratio changes at different temperatures.The variations in the experimental conditions have resulted in different and even contradictory results. There is specifically few experimental works conducted on Athabasca oil systems, and previously reported trends mainly apply to less viscous oils. This implies that the actual effect of temperature on flow behavior of fluids in the rock is case specific. Due to the contradictory reports and conclusions, which are due to variation in the systems being tested, it seemed necessary to conduct our own core flooding experiments, and investigate the curves of relative permeability. The objective was to obtain the imbibition relative permeability curves in an Athabasca oil type reservoir at different temperatures and oil viscosities, and figure out any possible trends of variations with temperature.Before conducting the core flooding experiments, some fluid behavior experiments were done to figure out the properties of bitumen used in this study. These include fluid compositions, density, viscosity, molecular weight and oil/steam interfacial tension. These properties were further used in numerical simulation studies.Core floodings were conducted on glass bead packs and sand packs saturated with heavy oils with varying viscosities. Displacement experiments with water were performed at different temperatures, and unsteady-state method of relative permeability measurement was conducted. The relative permeability data were determined by history matching the oil production data and pressure differential data in each experiment.Results indicated a change in the water saturation range in the oil-water relative permeability curves. The shift was towards higher water saturations, meaning an increase in irreducible water saturation and a decrease in residual oil saturation. Regarding the shape of relative permeability data, no unique trend of either rising or falling with temperature was found for oil and water relative permeability curves. The viscous instabilities are believed to be present in the experiments.As the same saturation range shift occurs by comparing the results at the same temperature level and by only changing the oil viscosity, this suggests that the temperature dependency of relative permeabilities can be attributed to the drop in oil to water viscosity ratio by temperature.The variations of relative permeability data with temperature was therefore found to be more related to artifacts in the experimental procedures like viscous fingering, and fluid viscosity changes than fundamental flow properties.Numerical simulations were accomplished on field scale SAGD and ES-SAGD (Expanding Solvent SAGD) operations testing the effect of relative permeability curves. Temperature dependent relative permeability data were tested and Oil production was found to be strongly dependant on the end point data. It is therefore suggested to use this option as a matching criterion when trying to history match SAGD field data.Since the main experimental part of this study deals with temperature dependency of relative permeability data, the introduction of this thesis is totally devoted to introducing this concept and its measurement methods and a literature review on the works performed so far. The main thesis is composed of three main parts, the fluid behavior experiments on bitumen, one-dimensional flow studies and multi-dimensional flow part. The results of fluid behavior experiments are given in chapter 2. Chapters 3 and 4 are devoted to one-dimensional flow works and chapters 5 and 6 present the part of this thesis dealing with two and three-dimensional flow. It should, however, be mentioned that chapters 4 to 6 can be read independently, as the contents of these chapters are taken from previously published papers with some minor revisions.

Numerical Simulation Study of SAGD Experiment and Investigating Possibility of Solvent Co-Injection

Heavy oil and tar sands are important hydrocarbon resources that are destined to play an increasingly important role in the oil supply of the world. A huge proportion of total world oil resources are in the form of these highly viscous fluids. The main recovery mechanism for these kinds of reservoirs is to somehow reduce their viscosity by the application of heat. In these extra heavy oil reservoirs, the reservoir has almost no injectivity, and therefore conventional steam flooding is hard to conduct. Steam Assisted Gravity Drainage (SAGD), however, reduces the viscosity of bitumen in place and the heated bitumen drains due to gravity forces towards the production well, where it is produced. Modeling and evaluating the production mechanisms in this process requires a thorough understanding of multi-phase flow parameters like relative permeability.Relative permeability data depend on a number of different parameters among others temperature and fluid viscosity. Viscosities of the flowing fluids drop with temperature, which can affect the relative permeability data. There has been a long debate on the actual impact of temperature on the relative permeabilities. Although some authors have reported saturation range shifts and relative permeability curve variations by temperature, others have attributed these variations to artifacts inherent in the methods used and the systems tested. Viscous instabilities and fingering issues have been blamed for temperature dependencies reported, and some researchers have reported that relative permeability data changes due to oil/water viscosity ratio changes at different temperatures.The variations in the experimental conditions have resulted in different and even contradictory results. There is specifically few experimental works conducted on Athabasca oil systems, and previously reported trends mainly apply to less viscous oils. This implies that the actual effect of temperature on flow behavior of fluids in the rock is case specific. Due to the contradictory reports and conclusions, which are due to variation in the systems being tested, it seemed necessary to conduct our own core flooding experiments, and investigate the curves of relative permeability. The objective was to obtain the imbibition relative permeability curves in an Athabasca oil type reservoir at different temperatures and oil viscosities, and figure out any possible trends of variations with temperature.Before conducting the core flooding experiments, some fluid behavior experiments were done to figure out the properties of bitumen used in this study. These include fluid compositions, density, viscosity, molecular weight and oil/steam interfacial tension. These properties were further used in numerical simulation studies.Core floodings were conducted on glass bead packs and sand packs saturated with heavy oils with varying viscosities. Displacement experiments with water were performed at different temperatures, and unsteady-state method of relative permeability measurement was conducted. The relative permeability data were determined by history matching the oil production data and pressure differential data in each experiment.Results indicated a change in the water saturation range in the oil-water relative permeability curves. The shift was towards higher water saturations, meaning an increase in irreducible water saturation and a decrease in residual oil saturation. Regarding the shape of relative permeability data, no unique trend of either rising or falling with temperature was found for oil and water relative permeability curves. The viscous instabilities are believed to be present in the experiments.As the same saturation range shift occurs by comparing the results at the same temperature level and by only changing the oil viscosity, this suggests that the temperature dependency of relative permeabilities can be attributed to the drop in oil to water viscosity ratio by temperature.The variations of relative permeability data with temperature was therefore found to be more related to artifacts in the experimental procedures like viscous fingering, and fluid viscosity changes than fundamental flow properties.Numerical simulations were accomplished on field scale SAGD and ES-SAGD (Expanding Solvent SAGD) operations testing the effect of relative permeability curves. Temperature dependent relative permeability data were tested and Oil production was found to be strongly dependant on the end point data. It is therefore suggested to use this option as a matching criterion when trying to history match SAGD field data.Since the main experimental part of this study deals with temperature dependency of relative permeability data, the introduction of this thesis is totally devoted to introducing this concept and its measurement methods and a literature review on the works performed so far. The main thesis is composed of three main parts, the fluid behavior experiments on bitumen, one-dimensional flow studies and multi-dimensional flow part. The results of fluid behavior experiments are given in chapter 2. Chapters 3 and 4 are devoted to one-dimensional flow works and chapters 5 and 6 present the part of this thesis dealing with two and three-dimensional flow. It should, however, be mentioned that chapters 4 to 6 can be read independently, as the contents of these chapters are taken from previously published papers with some minor revisions.