The oil production from well fractured carbonate reservoirs is a considerable part of the total oil production in the world. The petroleum resource base in naturally fractured reservoirs is estimated to be in the range of billions of barrels in the U.S and in addition, a multibillion- barrel international oil resource base exists in naturally fractured reservoirs. Gravity drainage is important in some of oil recovery processes, either acting as the driving force in processes using horizontal wells or altering the displacement patterns during water-flooding, chemical flooding, CO2 flooding and other EOR methods. The gravity drainage process has a major effect on oil recovery from oil reservoirs. Gravity drainage driven oil production in naturally fractured and other complex reservoirs falls into two regimes: the balk flow regime and the film flow regime. Oil recovery by gravity drainage in a fractured reservoir strongly depends on the capillary height of the porous medium. Capillarity and gravity forces are usually the major driving forces in fractured reservoirs. This PhD thesis consists of two main parts namely: 1) Experimental works on gravity drainage, and 2) Modeling and simulation of the gravity drainage processes using COMSOL® software. An appropriate design of experiment (DOE) method was selected to find the most important parameters contributing in gravity drainage and then conduct the experiments in a useful as well as economic manner. A two-dimensional experimental setup was employed to investigate free fall gravity drainage (FFGD) and controlled gravity drainage (CGD) using unconsolidated glass beads fractured porous media having various fractures configurations. Flow visualization measurements were carried out. Following the flow visualization experiments, parametric sensitivity analysis was performed considering the effects of different system parameters such as fracture aperture, matrix height, permeability, and fluid properties on the dependent variables including drainage rate, critical pumping rate, maximum drainage rate, recovery factor and so on. These experiments enabled us to capture some aspects of the recovery mechanism and the flow communication between matrix block and fracture during gravity drainage. After analyzing the experimental data for the FFGD test runs, it was found that the rate of liquid flowing from matrix to fracture is proportional to the difference of liquid levels in the matrix and in the fracture. In addition, the characteristic rate and the maximum liquid drainage rate from the fractured models were determined for such a stable gravity-dominated process. The experiments showed that the presence of fracture is more influential in lower matrix permeability systems. For a given fracture-matrix system with different initial liquid saturation conditions, it was seen that the production history can be correlated by plotting the fraction of recoverable liquid as a function of time. Furthermore, the recovery factor can be correlated using dimensionless numbers such as the Bond number and the dimensionless time. For the controlled gravity drainage (CGD) test runs conducted, the experimental results indicated that higher pumping rates cause a higher difference between the liquid levels in the fracture and in the matrix, thus the gas breakthrough happens sooner. Moreover, it was found that as long as the porous medium is drained with a constant liquid pumping rate but lower than critical rate, the height difference between the G-L interfaces in matrix and fracture remains constant. In this study, a new concept of “Critical Pumping Rate” (CPR) was defined at which each particular porous medium has recovery factor equal to the recovery factor for higher rates just before gas breakthrough. The difference between liquid levels in fracture and matrix remains unchanged at rates higher than CPR. Known this particular withdrawal rate, there are two main advantages, namely: 1) choosing a pumping rate lower than it to drain the reservoir without getting gas breakthrough; and 2) understanding the physics of pumping behaviour from fractured media and extending the concept to the real cases. In addition, the maximum liquid pumping rate from each physical model was studied and it was found that the rate depends strongly on the storage capacity of the fractures, petrophysical properties of each model as well as physical properties of test fluids. The critical rate, maximum rate, recovery factor at gas breakthrough and difference of gas liquid interface positions in matrix and fracture were correlated by dimensionless numbers such as Bond number, Capillary, and the ratio of permeabilities. Linear regression correlations presented in this study can predict production history and flow behaviour in the fractured porous media for a wide range of dimensionless numbers. The COMSOL® software was used to numerically simulate the gravity drainage processes in the two-dimensional flow experiments for fractured porous media. The parameters of the model were based on theory, as well as on the results of the two-dimensional gravity drainage experiments. The simulation results for the gravity drainage processes compared favourably with the experimental results, as a good match between the numerical solution and the experimental data was found. The simulation model developed provides a basis for further modeling of gravity drainage process in more complicated porous media.

The oil production from well fractured carbonate reservoirs is a considerable part of the total oil production in the world. The petroleum resource base in naturally fractured reservoirs is estimated to be in the range of billions of barrels in the U.S and in addition, a multibillion- barrel international oil resource base exists in naturally fractured reservoirs. Gravity drainage is important in some of oil recovery processes, either acting as the driving force in processes using horizontal wells or altering the displacement patterns during water-flooding, chemical flooding, CO2 flooding and other EOR methods. The gravity drainage process has a major effect on oil recovery from oil reservoirs. Gravity drainage driven oil production in naturally fractured and other complex reservoirs falls into two regimes: the balk flow regime and the film flow regime. Oil recovery by gravity drainage in a fractured reservoir strongly depends on the capillary height of the porous medium. Capillarity and gravity forces are usually the major driving forces in fractured reservoirs. This PhD thesis consists of two main parts namely: 1) Experimental works on gravity drainage, and 2) Modeling and simulation of the gravity drainage processes using COMSOL® software. An appropriate design of experiment (DOE) method was selected to find the most important parameters contributing in gravity drainage and then conduct the experiments in a useful as well as economic manner. A two-dimensional experimental setup was employed to investigate free fall gravity drainage (FFGD) and controlled gravity drainage (CGD) using unconsolidated glass beads fractured porous media having various fractures configurations. Flow visualization measurements were carried out. Following the flow visualization experiments, parametric sensitivity analysis was performed considering the effects of different system parameters such as fracture aperture, matrix height, permeability, and fluid properties on the dependent variables including drainage rate, critical pumping rate, maximum drainage rate, recovery factor and so on. These experiments enabled us to capture some aspects of the recovery mechanism and the flow communication between matrix block and fracture during gravity drainage. After analyzing the experimental data for the FFGD test runs, it was found that the rate of liquid flowing from matrix to fracture is proportional to the difference of liquid levels in the matrix and in the fracture. In addition, the characteristic rate and the maximum liquid drainage rate from the fractured models were determined for such a stable gravity-dominated process. The experiments showed that the presence of fracture is more influential in lower matrix permeability systems. For a given fracture-matrix system with different initial liquid saturation conditions, it was seen that the production history can be correlated by plotting the fraction of recoverable liquid as a function of time. Furthermore, the recovery factor can be correlated using dimensionless numbers such as the Bond number and the dimensionless time. For the controlled gravity drainage (CGD) test runs conducted, the experimental results indicated that higher pumping rates cause a higher difference between the liquid levels in the fracture and in the matrix, thus the gas breakthrough happens sooner. Moreover, it was found that as long as the porous medium is drained with a constant liquid pumping rate but lower than critical rate, the height difference between the G-L interfaces in matrix and fracture remains constant. In this study, a new concept of “Critical Pumping Rate” (CPR) was defined at which each particular porous medium has recovery factor equal to the recovery factor for higher rates just before gas breakthrough. The difference between liquid levels in fracture and matrix remains unchanged at rates higher than CPR. Known this particular withdrawal rate, there are two main advantages, namely: 1) choosing a pumping rate lower than it to drain the reservoir without getting gas breakthrough; and 2) understanding the physics of pumping behaviour from fractured media and extending the concept to the real cases. In addition, the maximum liquid pumping rate from each physical model was studied and it was found that the rate depends strongly on the storage capacity of the fractures, petrophysical properties of each model as well as physical properties of test fluids. The critical rate, maximum rate, recovery factor at gas breakthrough and difference of gas liquid interface positions in matrix and fracture were correlated by dimensionless numbers such as Bond number, Capillary, and the ratio of permeabilities. Linear regression correlations presented in this study can predict production history and flow behaviour in the fractured porous media for a wide range of dimensionless numbers. The COMSOL® software was used to numerically simulate the gravity drainage processes in the two-dimensional flow experiments for fractured porous media. The parameters of the model were based on theory, as well as on the results of the two-dimensional gravity drainage experiments. The simulation results for the gravity drainage processes compared favourably with the experimental results, as a good match between the numerical solution and the experimental data was found. The simulation model developed provides a basis for further modeling of gravity drainage process in more complicated porous media.

Petroleum research is responsible for making previously unusable reservoirs economically viable and for limiting the environmental impact of petroleum development. Microfluidics, the study of fluid flow at the micro-scale, is predominantly used to study biological phenomena. Adapting microfluidics to study petroleum requires the use of materials and methods not commonly used. This thesis focuses on applying microfluidics to the study of petrochemical fluid flow at high-pressure and high-temperature. The first problem addressed is the study of fluids during alkaline steam assisted gravity drainage (alkaline SAGD). The addition of an alkaline additive is found to improve the bitumen production rate by 35-67%. Secondly, two high-pressure, high-temperature, solvent resistant microfluidic interfaces for glass chips are designed to be operated up to 140 bar and 70 degrees Celsius. Lastly, a novel method for fabricating solvent resistant microfluidic devices from Teflon film is demonstrated by measuring the viscosity of toluene-heavy oil blends.

Petroleum research is responsible for making previously unusable reservoirs economically viable and for limiting the environmental impact of petroleum development. Microfluidics, the study of fluid flow at the micro-scale, is predominantly used to study biological phenomena. Adapting microfluidics to study petroleum requires the use of materials and methods not commonly used. This thesis focuses on applying microfluidics to the study of petrochemical fluid flow at high-pressure and high-temperature. The first problem addressed is the study of fluids during alkaline steam assisted gravity drainage (alkaline SAGD). The addition of an alkaline additive is found to improve the bitumen production rate by 35-67%. Secondly, two high-pressure, high-temperature, solvent resistant microfluidic interfaces for glass chips are designed to be operated up to 140 bar and 70 degrees Celsius. Lastly, a novel method for fabricating solvent resistant microfluidic devices from Teflon film is demonstrated by measuring the viscosity of toluene-heavy oil blends.

To recover oil remaining in petroleum reservoirs after waterflooding, the gravitationally stable mode of gas injection is recognized as a promising tertiary oil recovery process. Understanding the phenomena occurring over the course of the gravity-assisted inert gas injection (GAIGI) process is thus important. Extensive studies on both secondary and tertiary modes of gravity drainage have shown promising results in recovering oil from homogeneous water-wet glass bead packs, sand packs, and sandstone cores, respectively. However, it is not realistic to anticipate similar flow mechanisms and recovery results in all types of reservoirs because the natural hydrocarbon reservoirs are all heterogeneous in terms of their permeability, porosity, and wettability. Such heterogeneities cause irregular displacement patterns, and nonuniform fluid distribution. The impact of heterogeneity of the porous media on the GAIGI process has not been fully addressed in the experimental studies carried out to date; therefore, this thesis aims to fill in the gap of knowledge on this area. The impact of reservoir wettability and pore structure heterogeneities at the macroscopic scale on the recovery efficiency of the GAIGI process was investigated through a systematic experimental study for tertiary recovery of waterflood residual oil. To obtain heterogeneous (in terms of wettability) packings, isolated inclusions of oil-wet consolidated glass beads were embedded in a continuum of unconsolidated water-wet glass beads. Similarly, the heterogeneous porous media exhibiting permeability heterogeneity consisted of large-pore-size isolated regions randomly distributed in a small-pore-size continuum. Upon waterflooding, significantly higher waterflood residual oil saturation was established in both cases of heterogeneous media in comparison to water-wet homogeneous porous media. The amount of waterflood residual oil varied linearly with the volume fraction of heterogeneities in the packings. Experimental results obtained from tertiary gravity drainage experiments demonstrated that the continuity of water-wet portions of the heterogeneous porous media facilitates the residual oil recovery through the film flow mechanism, provided that the oil spreading coefficient is positive. In addition, owing to the high waterflood residual oil content of the heterogeneous media tested, the oil bank formation occurred earlier and grew faster than that in homogeneous media, resulting in a higher oil recovery factor. However, the favorable wettability conditions in both the homogeneous and heterogeneous porous media exhibiting permeability heterogeneity resulted in slightly lower reduced residual oil saturation after the GAIGI process compared to that in the heterogeneous media with wettability heterogeneity under the same condition of withdrawal rate. In addition, the oil recovery factor at gas breakthrough was found to be inversely related to the production rate due to the functionality of gravity and viscous forces over the course of gravity drainage. These two forces were combined into a dimensionless form, defined as the gravity number (Ngv=Kogg/oVpg). It was discovered that there is a correlation between the oil recovery factor at gas breakthrough and the gravity number for both the heterogeneous and homogeneous media. The correlation of recovery factor at gas breakthrough versus the gravity number in heterogeneous media followed a similar trend as that found for homogeneous water-wet porous media. However, at a given gravity number, the recovery factor in heterogeneous media was greater than that in the homogeneous media. This implies that heterogeneous media will be better target reservoirs for applying the GAIGI process compared to the homogeneous reservoirs.

Relative permeabilities for three-phase flow are commonly predicted from two-phase flow measurements using empirical models. These models are usually tested against available steady state data. However, the oil flow is unsteady state during various production stages such as gas injection after water flood. Accurate measurement of oil permeability([subscript ro]) during unsteady tertiary gas flood is necessary to study macroscopic oil displacement rate under micro scale events including double drainage, coalescence and reconnection, bulk flow and film drainage. We measure the three-phase oil relative permeability by conducting unsteady-state drainage experiments in a 0.8m water-wet sandpack. We find that when starting from capillary-trapped oil, k[subscript ro] starts high and decreases with a small change in oil saturation, and shows a strong dependence on both the flow of water and the water saturation, contrary to most models. The observed flow coupling between water and oil is stronger in three-phase flow than two-phase flow, and cannot be observed in steady-state measurements. The results suggest that the oil is transported through moving gas/oil/water interfaces (form drag) or momentum transport across stationary interfaces (friction drag). We present a simple model of friction drag which compares favorably to the experimental data. We also solve the creeping flow approximation of the Navier-Stokes equation for stable wetting and intermediate layers in the corner of angular capillaries by using a continuity boundary condition at the layer interface. We find significant coupling between the condensed phases and calculate the generalized mobilities by solving co-current and counter-current flow of wetting and intermediate layers. Finally, we present a simple heuristic model for the generalized mobilities as a function of the geometry and viscosity ratio. To identify the key parameter controlling the measured excess oil flow during tertiary gasflood, we also conduct simultaneous water-gas flood tests where we control water relative permeability and let water saturation develop naturally. The measured data and pore scale calculations indicate that viscous coupling can not explain completely the observed flow coupling between oil and water. We conclude that the rate of water saturation decrease, which controls the pore scale mechanisms including double drainage, reconnection, and film drainage significantly influences the rate of oil drainage during tertiary gas flood. Finally, we present a simple heuristic model for oil relative permeability during tertiary gas flood, and also explain how Stone I and saturation-weighted interpolation should be used to predict the permeability of mobilized oil during transient tertiary gasflood. / text

The age of “easy” oil has steadily declined through the years as many conventional land-based fields have been depleted to residual levels. Novel technologies, however, have reawakened old fields, allowing incremental oil to be added to their recoverable oil in place (ROIP). Underground Gravity Drainage (UGD), an example of one of these technologies, combines improved horizontal and deviated drilling technologies with the longstanding concept of gravity drainage. In this work, a better understanding of gravity drainage has been gained through (1) development of a numerical, three-dimensional, three-phase reservoir simulator (UT-EMPRES), (2) development of a universal, semi-empirical model of production rates through primary depletion, and (3) analysis of the important aspects of gravity drainage through simulation. UT-EMPRES is a new three-phase, finite-difference reservoir simulator, which utilizes a simple, easy-to-use Microsoft Excel interface to access MATLAB-programmed simulation code. This simulator produces nearly identical results to other well-established simulators, including UTCHEM and CMG. UT-EMPRES has some unique features, allows for easy post-processing in MATLAB, and has been utilized extensively in the other two areas of this thesis. The generalized flow rate model (GFRM) is a semi-empirical equation that is used to forecast the dynamic primary production rate of a reservoir with an arbitrary number of wells all operating at the same constant pressure condition. The model is an extension of the classic tank model, which is inherently a single flowing phase development. With the ability to make a priori predictions of production figures, users can screen various prospect assets on the basis of economic potential through optimization routines on the GFRM. Gravity drainage and its approximation through numerical simulation are analyzed. A sensitivity study was conducted on three-phase gravity drainage, leading to the conclusion that small changes in vertical permeability and portions of the relative permeability-saturation relationships can greatly affect production rates. Finally, two-phase (oil and air) and regions of three-phase (water, oil, air) flow simulations were found to exhibit exponential decline in phase production rates, which may enable the GFRM to be applicable to UGD-type processes. / text

To recover oil remaining in petroleum reservoirs after waterflooding, the gravitationally stable mode of gas injection is recognized as a promising tertiary oil recovery process. Understanding the phenomena occurring over the course of the gravity-assisted inert gas injection (GAIGI) process is thus important. Extensive studies on both secondary and tertiary modes of gravity drainage have shown promising results in recovering oil from homogeneous water-wet glass bead packs, sand packs, and sandstone cores, respectively. However, it is not realistic to anticipate similar flow mechanisms and recovery results in all types of reservoirs because the natural hydrocarbon reservoirs are all heterogeneous in terms of their permeability, porosity, and wettability. Such heterogeneities cause irregular displacement patterns, and nonuniform fluid distribution. The impact of heterogeneity of the porous media on the GAIGI process has not been fully addressed in the experimental studies carried out to date; therefore, this thesis aims to fill in the gap of knowledge on this area. The impact of reservoir wettability and pore structure heterogeneities at the macroscopic scale on the recovery efficiency of the GAIGI process was investigated through a systematic experimental study for tertiary recovery of waterflood residual oil. To obtain heterogeneous (in terms of wettability) packings, isolated inclusions of oil-wet consolidated glass beads were embedded in a continuum of unconsolidated water-wet glass beads. Similarly, the heterogeneous porous media exhibiting permeability heterogeneity consisted of large-pore-size isolated regions randomly distributed in a small-pore-size continuum. Upon waterflooding, significantly higher waterflood residual oil saturation was established in both cases of heterogeneous media in comparison to water-wet homogeneous porous media. The amount of waterflood residual oil varied linearly with the volume fraction of heterogeneities in the packings. Experimental results obtained from tertiary gravity drainage experiments demonstrated that the continuity of water-wet portions of the heterogeneous porous media facilitates the residual oil recovery through the film flow mechanism, provided that the oil spreading coefficient is positive. In addition, owing to the high waterflood residual oil content of the heterogeneous media tested, the oil bank formation occurred earlier and grew faster than that in homogeneous media, resulting in a higher oil recovery factor. However, the favorable wettability conditions in both the homogeneous and heterogeneous porous media exhibiting permeability heterogeneity resulted in slightly lower reduced residual oil saturation after the GAIGI process compared to that in the heterogeneous media with wettability heterogeneity under the same condition of withdrawal rate. In addition, the oil recovery factor at gas breakthrough was found to be inversely related to the production rate due to the functionality of gravity and viscous forces over the course of gravity drainage. These two forces were combined into a dimensionless form, defined as the gravity number (Ngv=Kogg/oVpg). It was discovered that there is a correlation between the oil recovery factor at gas breakthrough and the gravity number for both the heterogeneous and homogeneous media. The correlation of recovery factor at gas breakthrough versus the gravity number in heterogeneous media followed a similar trend as that found for homogeneous water-wet porous media. However, at a given gravity number, the recovery factor in heterogeneous media was greater than that in the homogeneous media. This implies that heterogeneous media will be better target reservoirs for applying the GAIGI process compared to the homogeneous reservoirs.

Canada and Venezuela contain massive unconventional oil deposits accounting for over two thirds of newly discovered proven oil reserves since 2002. Canada, primarily in northern Alberta province, has between 1.75 and 1.84 trillion barrels of hydrocarbon resources that as of 2013 are obtained approximately equally through surface extraction or enhanced oil recovery (EOR) (World Energy Council, 2010). Due to their depth and viscosity, thermal based EOR will increasingly be responsible for producing the vast quantities of bitumen residing in Canada’s Athabasca, Cold Lake, and Peace River formations. Although the internationally accepted 174-180 billion barrels recoverable ranks Canada third globally in oil reserves, it represents only a 9-10% average recovery factor of its very high viscosity deposits (World Energy Council, 2010). As thermal techniques are refined and improved, in conjunction with methods under development and integrating elements of existing but currently separate processes, engineers and geoscientists aim to improve recovery rates and add tens of billions of barrels of oil to Canada’s reserves (Cenovus Energy, 2013). The Government of Canada estimates 315 billion barrels recoverable with the right combination of technological improvements and sustained high oil prices (Government of Canada, 2013). Much uncertainty and skepticism surrounds how this 75% increase is to be accomplished. This document entails a thorough analysis of standard and advanced EOR techniques and their potential incremental impact in Canada’s bitumen deposits. Due to the extraordinary volume of hydrocarbon resources in Canada, a small percentage growth in ultimate recovery satisfies years of increased petroleum demand from the developing world, affects the geopolitics within North America and between it and the rest of the world, and provides material benefits to project economics. This paper details the enhanced oil recovery methods used in the oil sands deposits while exploring new developments and their potential technical and economic effect. CMG Stars reservoir simulation is leveraged to test both the feasible recoveries of and validate the physics behind select advanced techniques. These technological and operational improvements are aggregated and an assessment produced on Canada’s total recoverable petroleum reserves. Canada has, by far, the largest bitumen recovery operation in the world (World Energy Council, 2010). Due to its resource base and political environment, the nation is likely to continue as the focus point for new developments in thermal EOR. Reservoir characteristics and project analysis are thus framed using Canada and its reserves. / text

Combustion assisted gravity drainage (CAGD) is an integrated horizontal well air injection process for recovery and upgrading of heavy oil and bitumen from tar sands. Short-distance air injection and direct mobilized oil production are the main features of this process that lead to stable sweep and high oil recovery. These characteristics identify the CAGD process as a high-potential oil recovery method either in primary production or as a follow-up process in reservoirs that have been partially depleted. The CAGD process combines the advantages of both gravity drainage and conventional in-situ combustion (ISC). A combustion chamber develops in a wide area in the reservoir around the horizontal injector and consists of flue gases, injected air, and mobilized oil. Gravity drainage is the main mechanism for mobilized oil production and extraction of flue gases from the reservoir. A 3D laboratory cell with dimensions of 0.62 m, 0.41 m, and 0.15 m was designed and constructed to study the CAGD process. The combustion cell was fitted with 48 thermocouples. A horizontal producer was placed near the base of the model and a parallel horizontal injector in the upper part at a distance of 0.13 m. Peace River heavy oil and Athabasca bitumen were used in these experiments. Experimental results showed that oil displacement occurs mainly by gravity drainage. Vigorous oxidation reactions were observed at the early stages near the heel of the injection well, where peak temperatures of about 550ºC to 690ºC were recorded. Produced oil from CAGD was upgraded by 6 and 2ºAPI for Peace River heavy oil and Athabasca bitumen respectively. Steady O2 consumption for both oil samples confirmed the stability of the process. Experimental data showed that the distance between horizontal injection and production wells is very critical. Close vertical spacing has negative effect on the process as coke deposits plug the production well and stop the process prematurely. CAGD was also laboratory tested as a follow-up process. For this reason, air was injected through dual parallel wells in a mature steam chamber. Laboratory results showed that the process can effectively create self-sustained combustion front in the previously steam-operated porous media. A maximum temperature of 617ºC was recorded, with cumulative oil recovery of 12% of original oil in place (OOIP). Post-experiment sand pack analysis indicated that in addition to sweeping the residual oil in the steam chamber, the combustion process created a hard coke shell around the boundaries. This hard shell isolated the steam chamber from the surrounding porous media and reduced the steam leakage. A thermal simulator was used for history matching the laboratory data while capturing the main production mechanisms. Numerical analysis showed very good agreement between predicted and experimental results in terms of fluid production rate, combustion temperature and produced gas composition. The validated simulation model was used to compare the performance of the CAGD process to other practiced thermal recovery methods like steam assistance gravity drainage (SAGD) and toe to heel air injection (THAI). Laboratory results showed that CAGD has the lowest cumulative energy-to-oil ratio while its oil production rate is comparable to SAGD.