Cost and thermal stability are the major obstacles in using chemical additives for enhanced heavy-oil applications. Visual analysis of biodiesel in water emulsions obtained from the bitumen recovery tests from previous studies demonstrated that high pressure steam can lead to formation of stable emulsion by evaporation of biodiesel and condensation of steam-biodiesel vapor in the reservoir. Hence, biodiesel can be an alternative to commercial surfactants as a low-cost and environmentally-friendly additive for hot and cold production of heavy-oil. For biodiesel to act as a surfactant and reduce IFT, it must first be condensated. Hence, we first studied the thermal-mechanical processing of biodiesel to generate stable steam treated homogenized biodiesel-in-water emulsion (SBDWE). Addition of chemicals such as silica and polymer (Xanthan gum) to further improve the stability of SBDWE was also considered in this study. Stable SBDWE samples generated at their optimal conditions were then employed for sandpack flooding experiments to observe their capacity to improve heavy oil recovery. In order to create stable SBDWE, biodiesel was first treated with steam at high pressure and high temperature conditions (1.6 MPa, 200°C). Variables such as reactor pressure, concentration of biodiesel in steam, and condensation time were modified independently to determine the optimal conditions for stable SBDWE generation. Surfactant behavior of the SBDWE samples was then tested through various methods (glass tube experiments, spreading tests through transmitted-light microscope, and naked eye visualization) The results from the experiments suggest that aggregation of the small-sized biodiesel droplets of SBDWE (~1μm) at the interface between heavy oil and SBDWE can form a stable emulsion phase. Creaming of SBDWE is a poor emulsification indication and can be avoided by controlling experimental variables such as injected volume of distillate water, concentration of injected biodiesel, soaking time, and addition of silica nanofluid. Storage of the stable SBDWE is also an important factor as SBDWE properties such as texture, color and stability can change over time. Injected water volume (representing steam) and soaking time are variables that can have a significant impact on the generation of stable SBDWE. Therefore, it is important to maintain a certain volume of water and soaking time during the homogenization treatment. Finally, displacement experiments on sandpacks with the help of low concentration of silica (1 wt. %) and Xanthan gum (0.35 wt.%) yielded additional recovery up to ~39%. Environmentally friendly and relatively inexpensive biodiesel (as a by-product of many industrial applications) is an ideal candidate for enhanced heavy oil recovery. Previously, application of biodiesel in heavy oil recovery came with limitations such that in enhanced heavy oil recovery, it is most effective when added to steam at high temperature and pressure conditions. However, the results from the laboratory scale cold flooding experiments with SBDWE demonstrated that SBDWE can be effectively used as a chemical additive using low concentrations of biodiesel.

The Lukeqin Triassic reservoir in Xinjiang, China, is a heavy oil reservoir with high temperature and high salinity. The formation conditions are harsh. With the deepening of oilfield development, the reservoir enters into a high water cut period and faces the problem of stable oil and water control in the middle and late stage of development. In addition, the heavy oil reservoir has complex characteristics, such as deep, thin, thick and so on, so it can not be converted to conventional thermal recovery mode. Therefore, a solution to the reservoir conditions is urgently needed. In order to improve the mobility ratio of water drive, a new type of high temperature resistance and high salinity polymer SWP322 has been developed. In this study, the compatibility, viscosity, temperature resistance, salt resistance and shear resistance of the polymer in Lukeqin reservoir were evaluated and compared with that of HPAM. Finally, the formation conditions of Lukeqin reservoir are simulated to test the percolation and oil displacement ability of the new polymer SWP322 under the conditions of high temperature and high salinity. Experiments show that the polymer has a temperature resistance of 100°C and a salinity resistance level of 2.0×105 mg/L. The experimental results show that the polymer SWP322 has a lower dissolution rate at room temperature than HPAM, but its temperature resistance, salt resistance, shear resistance, and temperature resistance are far better than those of HPAM. With the increase of temperature and salinity, the apparent viscosity of HPAM decreased rapidly, while SWP322 was almost independent of temperature and salinity, and the viscosity retention rate was more than 99%; at the same time, the viscosity retention rate of SWP322 after core shearing also reached 98.6%, which proves that SWP322 is superior to HPAM in its resistance to temperature and salt, and excellent shear resistance also helps to maintain the viscoelasticity of the polymer in the formation. Increase oil displacement efficiency. In terms of seepage capacity, the flow resistance of SWP322 is much better than that of HPAM, and the resistance coefficient and residual resistance coefficient are all more than 5 times that of HPAM; in the process of simulated oil displacement, the displacement efficiency of water flooding is 30.43%, while the flooding efficiency of first polymer flooding and subsequent water flooding is 16.6% higher than that of water flooding; the oil displacement efficiency of double-pipe polymer flooding is 13.19% higher than that of water flooding; the oil displacement efficiency of single tube and double tube flooding system is 16.1% and 23.2% higher than that of water flooding, respectively.

Preformed Particle Gels are successfully used for profile control in heterogeneous reservoirs. However, it is still unclear how to select proper PPG size for a given heterogeneous reservoir. In order to obtain the best profile control performance, it is necessary to study the matching relationship between the PPG mesh and the permeability ratio. In this paper, the heterogeneous parallel-dual-sandpack experimental setup is established, including the injection system, measurement systems for temperature and pressure. During the experimental processes of water injection, PPG injection and subsequent water injection, the fractional flow of the two sandpacks with high and low permeability are recorded respectively. Then, a quantitative characterization parameter of the profile improvement ability is defined by dividing the change of fractional flow of the low permeable sandpack before and after PPG injection by that of low permeable sandpack before PPG injection. The experimental results show that different PPG meshes will achieve different profile control performance for the heterogeneous sandpack with the determined permeability ratio. The PPG with excessive large size may block the low permeable area, decrease its fractional flow and thus cause more severe flow heterogeneity. The PPG with excessive small size can not well block the high permeability area and they can migrate out during subsequent water injection resulting in the increase of fractional flow in high permeable area again. The matching relationship analysis show that the matched PPG mesh increases as the permeability ratio of the heterogeneous sandpack increases. In detail, the matched PPG sizes for the permeability ratio of 2, 4, and 6 are 120-150 mesh, 100-120 mesh and 60-80 mesh, respectively. The paper studied the matching relationship between PPG size and permeability heterogeneity, which was beneficial for selecting the proper PPG size for different heterogeneous reservoirs in more future applications.

Clay minerals are commonly observed in the Neogene succession of North Kuwait, both in the two viscous oil rich sandstone reservoirs (S1, S2) and intervening shale layers. SEM and XRD analysis of the core samples explain that Smectite is the dominant and Palygorskite, Illite and Kaolinite as minor clay mineral constituents. The paper describes the vertical and lateral distribution of these minerals in different sedimentary facies from bottom to top and the impact of steam on them. The bottom and second channel-dominated sand and intervening shale (S2B sand, S2 Shale, S2A sand) layers show variation in total average clay content, as well as the swelling clay (smectite, illite-smectite) and fibrous palygorskite, with a low content in the north and center (2-4.6%), a moderate content in the east (6.7-7.3%) and a high content in the south (11.2-14.4%). The Middle shale layer (MShale), is recognized as a flooding surface, observed at base of muddy interdistributory bay/lagoonal or floodplain deposits, sharply overlaying the channel-filled sandstones. Smectite –Illite is the dominant clay constituent. The first channel-dominated sand and intervening shale (S1B sand and S1 Shale) layers contain predominantly smectite, illite-smectite and palygorskite content. The northern, southwestern and southeastern parts of the field, with more argillaceous channels and floodplain facies associations, have a high average total clay content (9.6-20%). The central part of the field, which is predominantly contains clean channel sand bodies, has a lower, average total clay content (4.9-12.6%). The topmost sand (S1A sand) layer contains higher proportion of muddier channels and interdistributary bay facies, in the northern part and has high (>7%) total clay content, but generally <2% swelling clays and palygorskite. The central part of the field, with clean channel sands, has relatively low (<7%) total clay content, with 0.8-3.2% swelling clays and palygorskite. The southern part of the field, with argillaceous channels, has a relatively high (>7%) total clay content, with 2.2-6.3% swelling clays and palygorskite. The sealing Cap Shale (bound by maximum flooding surface at the base and an erosive surface at the top) comprises of marine and restricted marine shales capping the underlying S1A sandstones. The clay mineral comprises of illite-smectite, kaolinite and chlorite, with no palygorskite content, As this viscous oil is planned to be produced by thermal applications, Clay stabilization experiments were conducted to ascertain the permeability reduction in the reservoir due to swelling of clay minerals and changes after exposure to steam. The steam flood experiments are conducted at 32, 65 and 232°C on actual core plugs and the conversion of Illite-smectite to smectite was observed, reducing the permeability. Chemical stabilizers were suggested for controlling these damaging effects at higher temperature.

There are ongoing efforts to assess the techno-ecnomic viability of surfactant polymer (SP) flooding to increase oil recovery by improving microscopic and macroscopic sweep efficiency. This paper sheds light on a methodology to design an appropriate SP formulation for potential deployment in the Ratqa Lower Fars (RQLF) heavy oil reservoir in Kuwait. Besides achieving low residual oil saturation due to SP flooding under typical RQLF reservoir conditions, this study focuses on mitigating surfactant retention. Several injection strategies were investigated using alkali, adsorption inhibitors and a variety of water treatment techniques. For each scenario, a specific SP formulation was designed and evaluated through static adsorption tests using crushed reservoir rock. The two most promising options were then evaluated through coreflood experiments. The best option was selected based on in-depth chemical propagation, oil desaturation and surfactant adsorption. Finally, lab-optimization work was performed through additional corefloods to reduce chemical consumption while maintaining favorable oil recovery. Softened seawater obtained through reverse osmosis was considered as the most appropriate water source to implement the desired SP process. Previous work revealed that the use of unsoftened seawater results in high levels of surfactant adsorption on reservoir rock. Salt addition allows applying an efficient salinity gradient post SP injection. Sodium chloride was used instead of alkali which did not exhibit any benefit in this case. A particular effort was made to reduce the amount of added salt and the corresponding formulation cost. Several injection sequences were investigated to compare polymer and SP flooding. The final coreflood experiment based on SP injection (0.6 PV of surfactant at 4 g/l), followed by a salinity gradient, and involving a polymer drive recovered 80% of the original oil in place. The promising performance of this injection sequence will be further evaluated using the results from a one-spot EOR pilot. This EOR study on the RQLF shallow heavy oil reservoir in Kuwait provides important insights to select an appropriate surfactant-polymer injection strategy to increase oil recovery while maintaining reduced adsorption levels, thereby improving SP techno-economic viability.

Oil-solvent mixing is essential during solvent injection applications to reduce the viscosity of oil but mass transfer by diffusion becomes slower as the oil becomes heavier. Thus, an interface exists between oil and solvent at certain times being stronger in the beginning of the process. This results in an immiscible displacement controlled by the capillary forces while mixing is in progress. It is of practical and fundamental importance to determine the mechanisms responsible for the displacement of heavy oil and the behavior of solvent (acting as both immiscible and miscible displacement agent) as it could be advantageous to accelerate the dilution of heavy oil in many circumstances, including heterogeneous (fractured, layered, wormholed) systems. This is a complex process consisting of multiple pore phases (oil, solvent, their mixtures, aqueous and vapor phases) at the same time while different mechanisms such as capillary imbibition, miscible interaction (diffusion and convection), and gravity also act simultaneously. To investigate this complex phenomenon for different oil-solvent systems, a novel experimental method was employed. The underlying mechanisms that dominate the solvent displacement process were comprehensively identified. The movement and evolution of interfaces among different fluid phases in glass capillary tubes was observed and recorded. The oil samples with different viscosities were utilized to examine the effects of oil viscosity on the mass transfer accelerated by imbibition transfer. The effects of temperature, wettability and boundary conditions on the interaction of miscible fluids pairs were also studied. Pentane, heptane and decane were used as the solvent phases. Advanced photographic techniques using UV light and dyed fluids were applied to better track the flow of different phases in the mixing zone. The experiments demonstrated a slowly smearing interface between solvent and viscous oil. A unique natural convection was induced with the combined effect of gravity, diffusion (mixing) and capillarity all contributing to the recovery of heavy-oil. Based on the saturation method, boundary condition and the Bond number, four different motion modes of mixing zone and interfaces of miscible fluids in the capillary tube were unveiled and categorized to identify the degree of interface development (immiscible flooding). Also, the mixing zone, mass flux, and flow behavior were quantified using dimensionless parameters. The results indicate that priority may be given to a solvent with a high interfacial tension for solvent-based oil recovery technique because of a strong imbibition and further enhancement of the dilution and displacement processes under condition of similar viscosity ratio. The data provided will be useful for the accuracy of modeling studies, especially for complex geologies where oil-solvent interaction is critically difficult to develop in order for mixing to occur.

Lower Fars heavy oil <16 °API is considered a type of conventional heavy oil, which will be considered as priority petroleum production system for future heavy oil recovery in Kuwait. These types of oils are abundant in great amounts in Ratga field North Kuwait, yet expensive to produce due to its high viscosity hence low mobility underground. Kuwait strategy is shifting focus to these types of oils since conventional medium oil and other less-quantitative-light-oil reservoirs are continuously depleting. The study's interest is directed towards a specific type of EOR oil, which is hot dry air sequestration into Lower Fars heavy oil. This study presents novel heavy oil recovery method for 14 °API crude oil using hot dry air as well as their potential recoveries. All recoveries considered for this study are bench-scale laboratory physical experiments with horizontal (0 °), vertical (90 °), and directional (45 °) continuous air diffusion augmented with applied different thermal heat treatments. The main objective for this research is to model recovery efficiency from this hot dry heat diffusion technique (HDAD). This technique will produce air diffusion design. This design will consider direction of blow diffusion for three possible well orientations: horizontal 0 degrees, vertical 90 degrees, and directional 45 degrees. Also, the design will consider six temperatures: 27 °C 30 °C 60 °C 70 °C 85 °C and 100 °C dry hot air diffusions. Moreover, the design will consider two diffusion velocities 74.08 km/hr and 111.12 km/hr. These velocities will determine designing the time of recovery, which is one hour, according to lab-time limitations and permissions. The main technology motivation for hot dry air diffusion (HDAD) research is finding the optimized economical EOR recovery efficiency factor that will extract most of 14 °API Lower Fars oil. The model determines the recovery potential factor in a classic, optimum and conventional economic scenario considering the energy usage to generate the hot dry air delivered to the reservoir. Also, HDAD technology usages will avoid the use of water technologies recoveries. Avoiding water technology recovery will minimize environmental impact, crude oil/ emulsions subsurface-mobility issues and costly water production management used at current steam economic challenges.

The use of catalysts has been considered as an effective method to improve the efficiency of in-situ combustion (ISC) process for heavy oil recovery. In this work, we present a new small-scale combustion tube to quickly and effectively evaluate the effect of catalysts on ISC process. Different oil-soluble metal-based catalysts were evaluated for ISC process for heavy oil recovery using this small-scale combustion tube. These experiments can provide the information about the stability of combustion front, oil recovery, and in-situ oil upgrading information. Using this device, ISC process was successfully simulated. It turned out that the ISC process itself can effectively improve heavy oil recovery up to about 70 % and simultaneously achieve an in-situ oil upgrading evidenced by a significant viscosity reduction and an API increase. The presence of oil-soluble iron-based, nickel-based and copper-based catalysts can achieve a further oil upgrading to the level of medium oil from heavy oil with a more significant reduction in the content of resins and asphaltenes. However, the in-situ oil upgrading in ISC process yielded by iron-based and nickel-based catalysts at the expense of an unstable combustion front and a lower oil recovery (about 10 % lower than that without catalysts). The presence of copper-based catalysts not only achieved a further oil upgrading, but also improved the stability of combustion front and yielded a higher oil recovery (about 5 % higher than that without catalysts). The obtained results indicated that oil-soluble copper-based catalyst has a great potential for improving the efficiency of ISC processes for heavy oil recovery. The new small-scale combustion tube was proven to have the ability for a fast and effective evaluation of the influence of catalysts on ISC processes.

Reaction kinetics between calcite and acid systems has been studied using the rotating disk apparatus (RDA). However, simplifying assumptions have been made to develop the current equations used to interpret RDA experiments to enable solving them analytically in contrast to using numerical methods. Experimental results revealed inadequacy of some of these assumptions, which necessitates the use of a computational fluid dynamics (CFD) model to investigate their impact on the RDA results. The objectives of the current work are threefold: (1) develop a CFD model to simulate the reaction in the RDA, (2) Identify the error associated with the assumptions in the original equations, and (3) develop a proxy model from the results that can accurately represent the reaction in the RDA. In developing the CFD model, the averaged-continuum approach was used to simulate the chemical reaction on the disk surface. Both Newtonian and non-Newtonian fluids were studied to investigate the adequacy of the equations’ assumptions. To validate the model, simulations were compared with experimental results. Experiments were run at 0.25, 0.5, 1, and 1.25M HCl with marble using the RDA at 250°F. Rotation speeds of 200, 400, 600, and 1,000 rpm were tested at each acid concentration. The diffusion coefficient was then calculated. Parameters of the CFD model were then adjusted to match the rock dissolved throughout the RDA experiments. The rock dissolved in the disk from the CFD model matched the results from the RDA experiments. The transition from mass-transfer to the kinetics-limited reaction behavior was captured by the CFD model. The velocity and viscosity profiles for both Newtonian and non-Newtonian fluids showed the effect of the container's boundaries on the flow. Results indicate that this effect is pronounced in the case of Newtonian fluids at high rotational speeds. Moreover, the impact of varying viscosities in the case of non-Newtonian fluids resulted in errors in estimating the reaction kinetics. Finally, a proxy model was obtained to reduce the computational time involved in accurately simulating the experiments. The present work developed the first CFD model to accurately evaluate reaction kinetics and diffusion coefficient in the RDA with minimum assumptions. More specifically, the model relaxes the infinite acting, constant fluid properties, and constant reaction surface area assumptions. Finally, the proxy model obtained results in reduced computational time with minimal compromise on accuracy.

Steam assisted gravity drainage (SAGD) is widely applied in the exploitation of oil sand reservoirs, however, the development process is affected by complex geological conditions, wherein the interlayer has a great impact. Specifically, it has a great influence on heat and mass transfer of steam and on the effective flow of crude oil. For this reason, the characteristics of steam chamber and the production performance were investigated in detail to clarify the influence mechanism of interlayer. In this paper, based on the reservoir parameters of Long Lake oil sands, a series of numerical simulations were conducted to study the characteristics of SAGD process with interlayers. First of all, the numerical simulation method was used to study the influence mechanism of interlayer on heat and mass transfer. Then, based on the above analysis, we reclassified the production stages. Finally, we completed a series of numerical simulations with different parameters of interlayer to determine the influence level of main factors. The results of temperature profile show that the upper zone of the interlayer is mainly heated by heat conduction, whereas the area far from the interlayer is heated by the coupling effect of heat conduction and heat convection, hence, the steam chamber above the interlayer develops slower and the steam chamber in the area without interlayer develops faster. At the same time, it can be seen from the oil saturation profile that a dead oil zone is formed near the formation just above the interlayer. In addition, the production stage is no longer the classic "three-stage", due to the interlayer, the oil production rate is fluctuating, appearing peak production. Finally, we summarized the regular of the influence of each parameters and determined the main parameters, we considered the location, size, porosity, permeability, and thermal conductivity of interlayer comprehensively, the results show that the influence of thermal conductivity is smaller than other parameters.

Changes in crude oil wetting of carbonate rock when treated with various surfactants was evaluated using the Washburn method by the sorption of crude oil into packed rock powders. This method served to circumvent the difficulties of direct contact angle measurements on rock-chips where the low interfacial tension between the crude oil and surfactant leads to the spreading and eventual escape of the oil droplet without being attached to the rock chip. Four surfactants were used in the study including an anionic alfa olefin sulfonate, a cationic quaternary ammonium salt, an amphoteric surfactant and a nanosurfactant. Rock powders from a carbonate rock with a mesh size between 80 and 100 were coated with the tested surfactant solutions and compacted in a sample holder for the sorption experiments. Crude oil was raised to the bottom of the powder pack and allowed to rise into the powder by capillarity. A sensitive balance was used to measure the mass of crude oil imbibing into the powder until imbibition ceased. A plot of the square of oil mass against time enabled calculation of the contact angle using the modified Washburn equation. Earlier, a sorption experiment using n-hexane was used to deduce the rock constant for the grain packing, which was necessary for calculation of the crude oil contact angle. The contact angle results demonstrated the surfactant solution's efficiency in altering the crude-oil wetting behavior. An increasing washburn contact angle through coating indicates that the carbonate rock is rendered less oil-wet, which implies better oil displacement. At ambient temperatures, the nanosurfactant gave the highest contact angle implying the least oil-wetting; in second place was the amphoteric surfactant. The anionic surfactant had little effect on oil-wetting while the cationic surfactant decreased oil-wetting to a lesser extent. At higher temperatures, the nanosurfactant maintained its superior effectiveness followed by the cationic and amphoteric surfactants. The anionic surfactant saw little change. The use of sorption to obtain contact angle of crude oil for rock surfaces treated with surfactants eliminates the difficulties associated with direct contact angle measurements for low and ultra-low surfactant solutions where attachment an oil-droplet is almost impossible. With the Washburn method rapid evaluation of surfactants ability to change rocks wettability can be made to better guide further evaluations of such processes. As the washburn method measures contact angle between solids and a liquid surrounded by air, the contact angles obtained are not to be interpreted directly as those obtained in a liquid-liquid environment.

For heavy oil recovery applications, mobility control is more important than interfacial tension (IFT) reduction and therefore, importance should be given to the recovery of remaining mobile oil by enhanced sweep efficiency. While the relative role of polymer's viscosity and elasticity on capillary-trapped residual light oil recovery has been studied extensively, their role on the sweeping the mobile viscous oil has not been explored. Injectivity is vital for heavy oil recovery applications and polymer selection criteria are done solely based on shear rheology. In this paper, the influence of viscous (shear) resistance and elastic (extensional) resistance of viscoelastic polymer on the mobile heavy oil recovery and injectivity is investigated through the combination of bulk shear/extensional rheology and single phase, and multiphase core flood experiments at typical reservoir flooding rate of 1 ft/day. Two polymer solutions with different concentration and salinity are selected such that low molecular weight (Mw) polymer (HPAM 3130) provides higher shear resistance than high Mw polymer (HPAM 3630). Extensional characterization of these two polymer solutions performed using capillary breakup extensional rheometer revealed that HPAM 3630 provided higher extensional resistance than HPAM 3130. The results show that the behavior of polymers in extension and shear is completely different. Two multiphase and two single-phase experiments are conducted at low flux rate to investigate the role of extensional viscosity on mobile heavy oil recovery and high flux rates on injectivity. After 1 PV of polymer injections, higher concentration and lower Mw HPAM 3130 contributes to ~17% higher incremental recovery factor over lower concentration and higher Mw HPAM 3630. The core scale pressure drop generated by HPAM 3130 is more than twice the pressure drop generated by HPAM 3630. Under low flux rate conditions at the core scale, shear forces dominate and displacing fluid with higher shear viscosity contribute to better sweep. HPAM 3630 exhibits shear thickening phenomenon and possess the apparent viscosity of ~ 90 cP at the flux rate of ~90 ft/day. Whereas HPAM 3130 continued showing shear thinning and has the apparent viscosity of around ~70 cP at ~ 90 ft/day. This signifies the role of extension rheology on the injectivity at higher flux rates. Results revealed that while extensional rheological role towards sweeping the mobile heavy oil recovery at low flux is lesser when compared to shear role, its negative role on the polymer injectivity is very significant. Polymer selection criteria for heavy oil recovery applications should incorporate extensional rheological parameters.

Enhanced oil recovery (EOR) from heavy oil reservoirs is challenging. The higher viscosity of oil in such reservoirs, add more challenges and severe the difficulties during any EOR method (i.e. high mobility ratio, inadequate sweep, reservoir heterogeneity) compared to that of EOR from light oil reservoirs. Foam has gained interest as one of the EOR methods especially for challenging and heterogeneous reservoirs containing light oil. However, the foam and especially polymer enhanced foam (PEF) potential for heavy oil recovery is less studied. The current study aims to evaluate the performance of CO 2 foam and CO 2 PEF during heavy oil recovery from both unconsolidated (i.e. sandpack) and consolidate (rock sample) porous media with the help of fluid flow experiments. The injection pressure profile, oil recovery, and CO 2 gas production were monitored and recorded to analyze and compare the performance of CO 2 foam and PEF for heavy oil recovery. A visual sandpack made of glass column and a core-flood system capable of measuring the pressure at different sections of the core were used in this study. Homogenous and fractured sandstone core samples, as well as a fractured carbonate core sample, were selected for the core-flood study. Static stability results revealed slower liquid drainage and collapse rates for PEF compared to that of foam even in the presence of heavy crude oil. The addition of polymer significantly improved the performance of CO 2 foam flooding during heavy oil recovery in dynamic experiments. This result was inferred from faster propagation rate, higher dynamic stability, and higher oil recovery of CO 2 PEF over CO 2 foam injection. Moreover, the visual analysis demonstrated more stable frontal displacement and higher sweep efficiency of PEF compared to the conventional foam flooding. In the fractured porous media, additional heavy oil recovery was obtained by liquid diversion into the matrix area rather than gas diversion inferred from pressure profile and gas production data. The results obtained from this study show that CO 2 PEF could significantly improve the heavy oil recovery and CO 2 sequestration, especially in homogeneous porous media.

Steam injection is one of the well-known thermal recovery processes that has been extensively applied to heavy oil reservoirs. Several efforts have been made to understand theoretical and practical aspects of steam injection and alkali flooding. However, the detailed information about the performance of steam-alkali flooding in field applications has not been deeply addressed yet. In this sense, in order to shed light on the background and applications in this area, this study comparatively investigates the efficiency of different strategies of pure steam injection and cyclic steam-alkali flooding in Bati Raman oil field, Turkey. Three experiments were conducted to evaluate the advantage of steam-alkali injection compared to pure steam injection for an 11.6° API Bati Raman crude oil. The steam injection system consists of two reservoirs for water and the alkali solution, an electrical pump, and an electric steam generator. Those three experiments are as follows; conventional pure steam injection, cyclic injection of steam and alkali solution 4.0 wt%, and cyclic injection of steam and alkali solution 8.0 wt%. Steam was injected with the rate of 10 ml/min at 110°C and the system pressure was set to be the atmospheric pressure. The liquid produced from the separators is sampled periodically to determine the oil recovery. Observation of sand packs after the experiments indicates the tendency for steam channeling in the vertical direction around the upper thermocouple. Since the upper thermocouple was inserted after the sand packing operation by pressing and rotation, steam could be passed through these channels without entering the all pores in the porous media. The average oil recovery by conventional pure steam injection, steam-alkali solution 4.0 wt% injection, and steam-alkali solution 8.0 wt% are 8%, 3% and 5.5% OOIP (original oil in place), respectively. This indicates that although the oil recovery in conventional pure steam injection was maximum, increasing the alkali concentration in the aqueous solution from 4% to 8% has caused the improvement in the recovery. The theoretical and practical information is supported by the experimental examples to evaluate the performance of different steam-alkali flooding strategies with Borax in heavy oil reservoirs of Bati Raman. This study also examines the challenges of steam-alkali flooding in extremely heavy oil reservoirs and explains that the pure steam injection is preferred due the insufficient change in interfacial tension during Borax injection process.

KOC's Umm Gudair/Abduliyah Tayarat reservoir has large oil reserves but is a challenging target due to low formation permeability and high oil viscosity. This study is focused on feasibility assessment of hybrid thermal and chemical methods incorporating both laboratory and simulation results. A recent updated static geological model for West Kuwait fields was used as the basis to generate a full-field dynamic reservoir model with representative reservoir geometry, heterogeneity, and complexity. Carter-Tracy aquifers were added to model lateral and bottom aquifers. Laboratory data were incorporated to model physiochemical properties. Gridblocks were globally refined to gain better resolution for heavy oil and EOR simulations. The full-field reservoir model was used to systematically study the potentials of hybrid thermal and chemical EOR methods in comparison with conventional waterflood and chemical EOR methods. Our studies show that in order to produce oil at an economic rate, long horizontal wells on the order of kilometers or horizontal wells stimulated by acidizing, multistage fracturing, or multiple laterals should be deployed. Vertical wells yield low oil production rates due to limited contact areas and severe water coning. Aquifer water intrusion from the west side of reservoir overshadows the bottom aquifer and the edge east side aquifer due to the heterogeneity of reservoir permeability. A sector model was extracted from the full-field Eclipse model and further refined to avoid grid effects in simulation of EOR processes. Simulation results show that hybrid thermal and chemical methods (hot polymer/Surfactant-Polymer/Alkaline-Surfactant-Polymer flood) can effectively increase oil recovery from high-permeability, high-saturation sweet spots of the Tayarat reservoir. With the help of horizontal wells, hot polymer flood shows the best performance after 20 years of oil production and yields more than 30% of incremental oil recovery. Hot Surfactant-Polymer flood shows slightly lower cumulative oil recovery but sustained oil production rates and less production decline in the late stage of the flood. Phase 2 coreflood experiments confirmed that hot polymer flood can effectively enhance oil recovery. In summary, this research study identified sweet spots for oil recovery and EOR applications in the challenging Tayarat reservoir and demonstrated the potential of producing significant amount of oil with appropriate IOR (e.g., extended reach horizontal wells, multistage fractures, stimulation, etc.) and EOR (e.g., hybrid thermal and chemical methods) techniques.

CO 2 injection has been used for several decades as a successful recovery method in enhanced oil recovery. The main impact of CO 2 is on lowering minimum miscibility pressure. However, the unfavorable mobility of CO 2 force us to use CO 2 with other methods such as water alternating gas to minimize this effect. Low temperature CO 2 injection may cover the role of the water and other fluids in this process. The injection of CO 2 at low temperatures open a unique opportunity to investigate the potential for usage of low temperature CO 2 as an enhanced oil recovery method. In this study, the effect of low temperature injection in a high temperature system is evaluated. Earlier studies suggested that this method could be beneficial. However, it is not verified by core flooding experiments. If proven effective, the usage of CO 2 would add its advantage along with its current huge economic and environmental advantages against other EOR methods. The results show that injection of low temperature CO 2 has a direct impact on recovery factor inside a high temperature system. The main outcome of this study is the proof for the effectiveness of low temperature CO 2 usage as early as a reliable secondary recovery method in macro scale without any major unfavorable effects such as early breakthrough and gravity override. This study provides an economic way to increase the recovery while minimum modifications of available techniques are needed. No chemical agents were used as the production cost should be minimized. In addition, this study provides the ability for CO 2 storage which also favors other conventional methods in terms of CO 2 emission.

This paper presents an extensive analysis solvent injection at elevated temperatures to recover heavy- oil/bitumen from fractured carbonates. Three different solvents (propane, heptane and distillate oil - naphtha) were injected at different temperatures representing a wide range of carbon number. Indiana limestone (outcrop) and vuggy naturally fractured carbonate samples (outcrop core samples from a producing formation in Mexico) were selected as core samples. Hot solvent was injected continuously through artificially fractured cores followed by hot water (or steam injection) phase. The optimal temperatures for heavy oil recovery and solvent retrieval, in the subsequent hot water injection, for each kind of rock sample and type of solvent were determined. The results revealed that heavy oil recovery increase with the solvent carbon number used. Also, it was observed that when the temperature is higher than the saturation value for the given pressure curve, the recovery decreases and the lightest component of the heavy oil are dragged by the gas stream.

Extreme heavy oil <5 °API is considered a type of unconventional tight oil, which will require a challenging petroleum production system for future new-generation extreme heavy oil or bitumen carbonate reserves. This oil is abundant in great amounts around the globe, yet is extremely difficult to produce due to its solid-like physical state locked deep underground. The world strategy eventually will shift focus to this type of oil since conventional and other less-quantitative-difficult reservoirs are continuously depleting. The interest of this study is directed towards a specific type of unconventional oil, which is available in tight carbonate reservoirs. Extreme heavy oil <5 °API exists in large quantities in Kuwaiti fields. This study presents a novel heavy oil classification especially for <5 °API crude oil types as well as their potential recoveries. All recoveries considered for this study are bench-scale laboratory physical experiments with toluene, de-ionized water and water-aided surfactants augmented with applied field thermal 25 °C, 135 °C, 225 °C and 315 °C heat treatments. The main objective for this research is to model five signature atoms available in almost all heavy crude oils: carbon, hydrogen, nitrogen, sulfur, and oxygen (CHNSO). These CHNSO fingerprints determine qualitatively and quantitatively the potential amount and quality of future extreme heavy crude oil recovery. An Artificial Intelligence (A.I.) neural network algorithm is developed for all possible conjecture atoms. A Multiple Layer Forward Feed (MLFF) learning system is designed, trained and applied for developing the A.I. neural network. Forty-one recovery models are manifested in this study, clustered in possible atom conjecture operational base-function domains, which are unary (one atom), binary (two atom), ternary (three atom), quaternary (four atom) and quinary (five atom) approach models. The main technological motivation for CHNSO research is finding the optimized conventional EOR recovery efficiency factor that will extract <5 °API oil. The model predicts the recovery potential factor in a classic, optimum and conventional economic scenario, considering the unconventional environmental impact, crude oil subsurface-mobility issues and technology limitations used as current economic challenges. The general summary of results suggest that CHNSO models are useful in better understanding and better predicting <5 °API oil recoveries. The three-atom nitrogen-sulfur-oxygen (NSO) ternary conjecture model has a significant impact regarding heavy crude oils, maximizing recovery in general, and extreme heavy oil potential recovery in particular, in regards to the difficult mobility of this type of crude oil.

Co-injection of solvents with steam increases the oil recovery factor and reduces significantly the environmental impact of steam injection processes. Nevertheless, the quality of the extracted bitumen is important to evaluate the process performance which is affected by the solvent-bitumen interaction. This interaction might lead to emulsion formation and asphaltene precipitation. These unfavorable flow assurance problems are associated with the behavior of asphaltenes in solvent-steam processes. Thus, it is important to observe the factors affecting the interfacial forces among asphaltenes-solvents-water prior to any field application. This work investigates the fundamental aspects of the solvent-bitumen interaction during solvent-steam injection processes. A Canadian bitumen was studied. The role of individual saturates, aromatics, resins, and asphaltenes (SARA) fractions of bitumen on solvent-steam process performance was examined both at liquid and vapor water conditions. The behavior of asphaltenes was investigated through systematic microscopic analyses with the absence and presence of reservoir rock. Also, the asphaltenes behavior after toluene (asphaltene soluble aromatic hydrocarbon) and n-pentane (asphaltene insoluble aliphatic hydrocarbon) addition was observed under the microscope. While toluene completely dissolves asphaltenes immediately, n-pentane leads to asphaltenes precipitation with bigger clusters. After these control experiments, the same tests were carried out with the addition of saturates and/or aromatics fractions of crude oil to the asphaltenes fraction. It showed that saturates lead to aggregation of asphaltene clusters at a higher rate than n-pentane, while aromatics dissolve the asphaltenes at a lower rate than toluene. Hence, it was found that the asphaltenes precipitating power of saturates is higher than n-pentane. However, results reveal that asphaltenes mainly interact with water and aromatics fraction of bitumen. The water-asphaltene interaction causes the emulsion formation and the aromatics-clay interaction is responsible for clay migration and higher amount of asphaltene precipitation. The results of this study help us to understand the factors acting upon displacement of bitumen during solvent-steam processes.

Water is one of the cheapest and the most abundant injection fluid for oil extraction. Hence, as the hydrocarbon production increases, the amount of water injected escalates which brings the necessity of the proper management and treatment of produced water. The produced water quality can vary greatly depending on water injection processes employed. Thus, we aim to develop a thorough understanding of the expected quality of produced water originating from different thermal enhanced oil recovery (EOR) processes to manage oilfield waters. In this study, produced water from steam flooding (SF), steam assisted gravity drainage (SAGD), solvent-SAGD (S-SAGD), hot water injection (HWI), and in-situ combustion (ISC) processes were characterized. The anions and cations were analyzed by an ion chromatography. Total dissolved solids (TDS), conductivity, pH, total organic content, and average particle sizes of colloids were measured. The stability of colloids was determined by Zeta potential. All analyses were performed on the produced water samples collected at different three stages of the processes; at the initial, intermediate, and final stage of each process. As expected, conductivity strongly correlated with the concentration of the ions present in produced water samples. Sulfate and total organic carbon (TOC) concentrations showed a linear relation. During steam and hot water based injection processes, which were conducted with quartz and kaolinite mixtures, clay-water interaction was found significant, and this interaction increases with injected fluid temperature. Based on zeta potential measurements, the produced water from steam based EOR processes exhibited higher stability than ISC. In other words, the colloids in produced water originated from ISC was more prompt to settlement which makes produced water from ISC good candidate for chemical coagulation. The steam based processes indicated lower TDS value in produced water than ISC, however, when the produced volumes were considered, ISC had advantages due to significantly low volumes of produced waters. Our results indicate that the proper selection of the bitumen extraction method impacts the bitumen-water interaction and produced water management becomes feasible.