Solvent Assisted-Steam Assisted Gravity Drainage (SA-SAGD) has been studied as a more efficient process for extracting bitumen from oil sands than the SAGD process. In the SA-SAGD process, solvent is injected with steam to decrease the viscosity of bitumen by dissolution of the condensed solvent. The dissolution of solvent causes a composition change of bitumen, which can lead to asphaltene precipitation. The effects of the asphaltene precipitation have been studied as part of a solvent-based recovery process such as Vapor Extraction (VAPEX). One of the advantages of the asphaltene precipitation is in-situ upgrading of the bitumen, whereas the disadvantage is that it causes a formation damage. To evaluate the effect of the asphaltene precipitation in the SA-SAGD process, it is essential to investigate the asphaltene precipitation under the conditions expected in the SA-SAGD process. However, it takes a lot of time to obtain sufficient data with a conventional method to quantify asphaltene precipitation under high-pressure/high- temperature (HP/HT) conditions. Therefore, the aim of this study is to develop an experimental procedure to evaluate the asphaltene precipitation with pressure/volume/temperature (PVT) apparatus in a reasonable time. The complex phenomenon at the edge of the chamber in the SA-SAGD process was simplified to a model of repetitions of mixing and drainage processes, and the experiment was configured in this manner. Solvent was added to a pre-diluted bitumen sample in a PVT cell. The supernatant liquid was sampled to analyze the asphaltene weight fraction remaining in the liquid phase and evaluate the asphaltene precipitation amount in the PVT cell. This process was repeated with increase in the solvent concentration. The asphaltene precipitation amount (APA) is calculated from the sample analysis data with recurrence relations under several assumptions. This procedure enables a wide range of APAs to be obtained from a mixture of bitumen and solvent in a single experiment, which enables sensitivity analysis under various conditions. In this research, the experiment was conducted under two different temperature conditions of 120°C and 150°C and the pressure was fixed at 3.5 MPa. The APA curves obtained from both experiments had almost the similar trend. Another important observation is that even the multi-component solvent (as used at the operation site) can still induce asphaltene precipitation under the HP/HT conditions expected in the SA-SAGD process.

The objective of this study is to examine the impact of polarity on surfactant-steam flooding performance in the recovery of a Canadian bitumen sample. 10 laboratory-scale core flood experiments were used to investigate the interaction between the polar head of surfactants and polar fractions of the bitumen sample (resins and asphaltenes) in the presence of steam. A Canadian bitumen from Alberta with high polar fraction content; resins (17 wt%) and asphaltenes (29 wt%), was selected. The bitumen sample was first characterized in terms of viscosity at reservoir temperature (10,000 cP) and API Gravity (12°). Then, coreflood tests were conducted by coinjecting steam with an anionic, a cationic, or a nonionic surfactant. The performance of three anionic, three cationic, and three nonionic surfactants was tested. Each core flood result was evaluated in terms of the cumulative oil recovery, the residual oil content, the produced oil quality, and the asphaltenes content of produced and residual oil samples. Then, bitumen's polar fractions (resins and asphaltenes) and bitumen itself were subjected to each surfactant solution under steam and liquid water conditions, and simultaneously their interactions were captured by an optical microscope. Analysis of microscopic images was used to explain the performance differences in each flooding test. Every surfactant-steam flooding process resulted in higher recovery than steam flooding alone. The greatest oil recovery was observed with the longest tail length anionic surfactant. It has been observed that the presence of asphaltenes in displaced oil inhibits the formation of microemulsions and consequently reduces the amount of produced oil. Further, we observed that the microemulsions are successfully formed between the resins fraction of bitumen sample and surfactant solution under steam condition. Hence, to maximize the effectiveness of surfactant processes in high asphaltenes content reservoirs, we highly recommend the use of asphaltenes precipitants prior to injection of any surfactant solutions.

Heavy oil in reservoirs exists in the form of either water in heavy oil (w/ho) emulsions after primary production under water drive, or during secondary recovery methods such as water or steam injection. In many cases, the decision to apply any secondary or tertiary methods such as CO 2 or CH 4 injection depends on the understanding of the behavior of these gases in w/ho emulsions at reservoir conditions. Such an understanding can reduce the uncertainties in reservoir modeling by providing an adequate fluid model for reservoir simulation and history matching studies. In this paper, we focus on the interfacial properties, relative volume change, and PVT behavior of CO 2 and CH 4 in (w/ho) emulsions. We first generated the (w/ho) emulsion using steam at 150oC. Next, the stability of our emulsion was tested using different criteria such as phase separation, viscosity of the produced emulsion compared with that of the starting oil, and the size and number of water droplets in the continuous medium. The experiments were run using two types of heavy oils that are collected from two representative fields in eastern Alberta, type A oil (27,000 cP) and type B oil (4,351 cP). A sensitivity analysis was performed to determine the impact of different operational variables such as water content in the emulsion, water pH, and flow rate; additionally, the role of asphaltene and resin in emulsion stability was investigated. The influence of water content in the emulsion was found to be critical and thus subsequent IFT and relative volume measurements as well as PVT analyses were conducted using emulsions of different water contents with a vol.% range from 10-70. The results were compared with a dead oil (no water) case. Two types of gases typically used to improve recovery in Alberta were tested: CO2 and CH 4 . IFT and volume measurements indicate the existence of critical water content which dramatically changes the behavior of the system; generally, emulsions with water content below this critical value exhibit lower IFT than the original oil, and the IFT falls steadily as the water content increases. The trend is reversed when the water content exceeds the critical value and IFT starts increasing before it stabilizes. This process happens when the water content reaches a vol.% higher than 50; however, it remains below that of the original oil. Regarding volume ratio, there seems to be a clear relationship between pressure and volume ratio of the emulsion and CO 2 system. Overall, volume ratio increases as pressure increases regardless of water content. In general, for experiments run with CO 2 , data suggests that water content affects the rate of expansion, but ultimately the final volume ratio remains the same. The results of this work are significant in that they indicate the phase behavior of w/ho emulsions, and that CO 2 and CH 4 can vary considerably depending on the composition of oil and water content in the system. IFT, relative volume, and PVT measurements provide key information needed to build an adequate fluid model to reduce the uncertainties in reservoir simulation and history matching.

Scale deposition and its treatment are crucial part of any thermal recovery method. High temperature variation, phase change associated with steam condensation and flashing, and complex flow dynamics of the wells make the thermal wells more susceptible to scale deposition. Several studies evaluated the type of scales collected from plugged sand screens; however, more investigation is required to address the reservoir conditions and wellbore hydraulics affecting the scaling potential of minerals at downhole conditions. A laboratory workflow combined with a predictive modeling toolbox to evaluate scaling tendency of minerals for different downhole conditions has been developed. First, saturation indices (SI) for different minerals were calculated at reservoir temperature and pressure using water chemistry analysis and the Pitzer theory. Then, the mineral composition of deposited materials collected from thermal wells in Athabasca and Cold Lake area were characterized using Scanning Electron Microscopy (SEM), Energy Dispersive X-Ray Spectrometry (EDS), Total Organic Carbon (TOC) and Inductively Coupled Plasma Mass Spectrometry (ICP-MS) analyses. Finally, a comparison analysis was performed between predictive and characterization results. The results of SI calculations showed that Mg-based silicates and Fe-based minerals are positive (SI>5) even at high temperatures (T>430 K). This indicates that the possibility of deposition for these minerals is high. Carbonates (calcite and aragonite) minerals are the most common depositing minerals. However, the extent of scaling index of carbonates is controlled by the concentration of Ca, HCO 3 , and CO 3 in the water sample. The characterization results confirm the results of modeling part. The results of SEM/EDS, ICP-MS analyses showed that carbonates, Mg-based silicates, and Fe-based corrosion products are the most common depositing materials among all minerals. The workflow presented in this study will help the industry to evaluate the scaling potential for thermal wells at different downhole conditions to make a proper decision to prevent plugging of the completion tools.

In heavy oil thermal wells, wellhead flanges are typically welded to casing pup-joints, with butt welding on the inner wall, and fillet welding on the outer wall. For the field operation, it was found that after 40 days of steam injection, approximate 50% of the wellhead production casing pup-joints exhibitedleakage, with longitudinal crack in casing joints. Fracture of the wellhead flange and the casing led to leakage of significant amount of toxic and harmful hydrogen sulfide which was not part of the l formation fluid. Ultrasonic flaw detection was performed on the failed casing joints. Andfound initiation of longitudinal cracks in the butt and fillet welds. Further tests were performed to obtain chemical composition, mechanical properties, charpy impact energy, and hardness values for the casing, flanges, and welds. The analysis showed poor weldability for the casing and flange materials, with weldability carbon equivalent greater than the critical value (≥0.6%). Microcracks were presented in the welds. Metallographic structure, material composition nearorigins of the cracks and crack propagation zone, and the welds were examined..Micro cracks along the wall thickness in fusion line and casing heat-affected zone were found. Note that the materialin the casingmiddlewallis tempered sorbite, with the nearby external surface of the weldmetallographic structureismartensite of phase transition. The weld and heat-affected zone had obvious phase transitions of IAF+B+F+P. Blind-hole method was used to quantifyhoop and axial stresses in the casing inner wall and the external fillet welds. It was found that location of the maximum hoop tensile stress coincided with the maximum tensile principal stress. With the maximum tensile residual stress 389MPa at 4 mm from the weld-fusion line in the casing external wall, and with the shielded metal arc welding heat-affected-zone width of 6-8.5 mm, the tensile residual stress in the heat-affected zone was 2.2 times higher than the residual stress in the casing body. The weld material at the maximum tensile residual stress location was tested for SSCC. Stress corrosion was observed for all threes specimens at ambient temperature within 12 hours. Using SEM method, the failure and SSCC analyses showed that the fracture morphology was flat and integunularfracture, and surface was covered with agglomerate corrosion products. Sulfur element was analyzed by means of EDS. It was found that the mass percent of S element in fracture secondary cracks coincided with the measured value of the SSCC fracture test. Therefore, it was concluded that the casing pup-joint longitudinal cracking was SSCC.related. Note that the polysulfone-drilling mud pyrolysis produces hydrogen sulfide was above 150 ° C at which H2S may be produced by the drilling mud. During stages with no steam injectat ambient temperature environment, using high grade SSCC non-resisitant thermal recovery well casing, as well as welding causedhigh residual stress, and high hardness martensite, were the main reasons for the longitudinal cracking in the casing. Therefore, it is recommended that the polysulfone-drilling mudshould not be used in drilling for thermal recovery wells. The use of welded connections should also be avoided or the undesired effects should be mitigated.

This paper presents the planning and execution process for a key matrix stimulation pilot project performed in the heavy-oil Chichimene field in the central Colombian province of Meta. An understanding of multiple aspects of formation damage, candidate well selection, laboratory testing, treatment fluid selection, onsite quality assurance/quality control (QA/QC), diversion considerations, and placement techniques was fundamental to achieving a successful treatment design. Results are presented in terms of a percentage increase in production rates, percentage decrease in decline rates, and skin value reduction. Because of current oil and gas industry economics, it is crucial to evaluate the return on investment for any well intervention campaign and apply an assurance process to help quantify the desired improvement in production results. This approach is primarily based on a workflow that includes several key steps: understanding the nature of and characterizing formation damage, reviewing necessary laboratory testing, validating candidate well selection, determining economically viable placement and diversion techniques, and performing QA/QC on site and post-treatment. Production results from the first five pilot wells are presented along with a review of the production decline and continuous improvement actions. Understanding the induced damage that can be caused by drilling operations, heavy-oil properties, and the potential for emulsion and wettability alteration, in addition to the need to ensure total fluid-fluid compatibility combined with low interfacial tensions (IFTs), can be crucial to achieving results above initial estimates. Aligned with current critical well intervention economics, a rigless operation with coiled tubing (CT) through the Y-tool of an electrical submersible pump (ESP) was selected instead of a traditional intervention with a workover (WO) rig. Because of long treatment intervals and large permeability variations, stages of foamed brine were included in the treatment schedule as a diversion method. A tuned frequency and amplitude tool was used to enhance the placement and effectiveness of the treatment as part of a CT bottomhole assembly (BHA). QA/QC sampling was valuable for treatment monitoring and enhancement. This paper presents a valuable basis for future candidate well selection and stimulation treatment design. The workflow and its application are a good reference for analogue fields in Colombia and other areas.

The phase behavior of heavy oil and propane mixtures was mapped from temperatures ranging from 20 and 180°C and pressures up to 10 MPa. Both vapour-liquid (VL) and liquid-liquid (LL) regions were observed. Saturation pressures (VL boundary) were collected in a Jefri 100 cm 3 PVT cell and blind cell apparatus. The propane content at which a propane-rich light phase and a heavy pitch phase formed (LL boundary) were visually determined with a high pressure microscope while titrating propane into the bitumen. High pressure and high temperature yield data were measured using a blind cell apparatus. Here, yield is defined as the mass of the indicated component(s) in the heavy pitch phase divided by the mass of bitumen in the feed. A procedure was developed and used to measure pitch-rich and propane-rich phase compositions in a PVT cell. Pressure-temperature and pressure-composition phase diagrams were constructed from the saturation pressure and heavy pitch phase onset data. High pressure micrographs demonstrated that, at lower temperatures and propane contents, the heavy pitch phase appeared as glassy particles while at higher yields and temperatures it appeared as liquid phase. Propane-free pitch yields as high as 70 wt% of the bitumen were observed. The propane contents of the pitch phase at 50°C and 2 MPa, 50°C and 5 MPa, and 130°C and 10 MPa (all for a feed of 50 wt% propane) were 22 ±0.4 wt%, 26 ±0.4 wt% and 2 ±1 wt%, respectively. The ability of a cubic equation of state to model the data was explored. The model with temperature dependent binary interaction parameters (BIP) matched the saturation pressures and the LL boundaries at one pressure. However, the model could not match the effect of pressure on the LL boundary. The model also underpredicted yields at high dilution and could not match the LL phase compositions.

Precipitation and deposition of asphaltene in reservoir rock can cause formation damage and reduce the fluid mobility, resulting in significant loss of the hydrocarbon production. A detailed study on asphaltene deposition behavior in porous media improves the understanding of asphaltene-induced formation damage and provides the possible solutions for preventing and/or controlling formation damage. Carbonate reservoirs in Western Canadian Sedimentary Basin (WCSB) have several challenges for enhanced oil recovery process (i.e. heterogeneity, the high viscosity of oil). Asphaltene-induced formation damage makes it more difficult for any process to recover heavy oil from such complex reservoirs. For advancements in understanding asphaltene deposition in fractured carbonate formations, asphaltene deposition behavior was analyzed with the help of pore scale observation during hydrocarbon solvent injection. Three types of solvent (nC5, nC7, and nC12) were used for solvent injection for extra-heavy oil recovery (30,000 cp at 22 °C). A uniquely designed heterogeneous-fractured micromodel imitating the fractured carbonate reservoirs was used for pore scale observation. A high-quality camera along with a microscope was utilized to capture images. SEM analysis was also performed on precipitated asphaltene to visualize the difference in the structure of the asphaltenes precipitated with different solvents. Observation through this study revealed that besides the amount of asphaltene deposition, the distribution pattern of asphaltene deposition could also be different when using various types of solvent. By increasing carbon number of solvent from C5 to C12, the amount of precipitation decreased while the wider distribution of deposited asphaltene was observed in a fractured-heterogeneous porous media. Moreover, it was noted that asphaltene could be deposited in different shapes that may or may not block the pore throat. The dominant flow mechanism (either diffusion dominant or viscous dominant) will affect the shape of deposited asphaltene. Asphaltene can deposit perpendicular or parallel to the flow direction which is in the form of parallel rope-shape deposits. The perpendicular deposits (usually in dominant diffusion flow), mainly observed in small pore throat, can block the diffusion path. However, the parallel shape deposits (typically in viscous dominant flow) will not significantly impede the flow path. The results of this study improve our understanding of different aspects of asphaltene-induced formation damage in the fractured carbonate reservoirs such as; susceptible locations of asphaltene deposition, different types/shapes of deposition which may or may not result in pore blocking, and effect of flow behavior and heterogeneity on asphaltene deposition and formation damage. The more we know about the asphaltene deposition in such heterogeneous reservoirs, the better we can control the formation damage and increase the effectiveness of heavy oil recovery processes.

World heavy oil and bitumen deposits contain more than twice the amount of crude compared to conventional reservoirs. Thermal production operations are used worldwide for heavy oil and bitumen production. Because of their nature, heavy oil and bitumen have a higher asphaltene content than conventional hydrocarbons. Asphaltene behaviour is affected by changes in pressure, introduction of gas to a reservoir, acidizing and other factors, including temperature. The effect of temperature on asphaltenes in heavy oil is still not well understood. The paper presents new data on asphaltene behaviour in thermal heavy oil and bitumen production operations. Liquid crystals in asphaltenes are detected when heat is applied. Temperature when liquid crystals appear in asphaltenes of heavy oil and bitumen is significantly lower than that for conventional oil. An assumption is made that this phenomenon is caused by the structure of asphaltenes, namely an enhanced amount of "archipelago" type molecules in asphaltenes. In situ combustion causes an increase of condensed aromatic compounds in asphaltenes, asphaltene transformation up to coke and deposition in porous media. The process changes the individual characteristics of the oil system. The individual characteristics of heavy oil do not change when steam injection technology is applied. The paper also provides data on viscosity of heavy oil and bitumen versus temperature as a function of heavy oil composition and the effect of ultrasound on heavy oil viscosity.

The growing market for solvent-assisted recovery methods, such as ES-SAGD, SAP, and LASER, increases the risk of asphaltene precipitation in the reservoir and upstream facilities that would result in production loss and huge operational costs. A comprehensive study on the asphaltene phase behaviour and precipitation is necessary in order to design preventive remedies for operational problems arising from asphaltene deposition. In the present study, we employed a cubic-plus-association equation of state (CPA-EOS) to model asphaltene precipitation from Alberta bitumen samples upon addition of n-alkanes. The focus of this work is to study the effect of temperature and solvent on the asphaltene precipitation. This method is, in particular, beneficial to commercial reservoir simulation due to its strong theoretical basis, reasonable calculation complexity, and modest computational time. The physical interactions were described by the Soave-Redlich-Kwong equation of state (SRK EOS). In the association term, the interactions between the bitumen pseudo-components were described based on the Wertheim's perturbation theory. Bitumen was characterized, based on SARA analysis, into two pseudo-components, namely the maltenes and asphaltenes. Self-association between asphaltene molecules and cross-associations between the hypothetical asphaltene and maltene molecules were considered. A solid-liquid equilibrium was assumed at the asphaltene precipitation onset. In order to satisfy the criteria for the formation of a solid phase, we employed a solid solubility model. The proposed CPA-EOS model has only one adjustable parameter, which decreased a lot of unnecessary computational time. This is especially important for systems containing complex materials such as bitumens and heavy oils. The adjustable parameter of the CPA-EOS model was found to be both temperature- and solvent-dependent such that it decreased with increasing temperature and increased with increasing solvent carbon number. Pressure did not have a significant effect on the model parameters for the dead bitumen samples and operational pressures well above the solvent's bubble point. The model predictions were compared with the experimental onset data for asphaltene precipitation over a range of temperature, and they were favourably in agreement. Our results showed that a tuned CPA-SRK EOS combined with the solid solubility model can successfully predict the onset of asphaltene precipitation. The results of the proposed model can be applied to the design and simulation of solvent-assisted thermal recovery methods and processes wherever bitumen comes in contact with heavy n-alkane solvents.

Chemical demulsification is a cost-effective, convenient, quick, and efficient method for breaking water-in-diluted bitumen emulsions in oil sands processing. The industry is always seeking demulsifiers that act as effective dehydrators and demineralizers, minimize rag layer formation by controlling oil/water interface, and reduce the diluent/bitumen losses to tailings. In this paper, the performance of a newly developed demulsifier “Z” was investigated for its performance on dilbit dehydration, demineralization, and hydrocarbon losses to tailings and compared against the first and second generation demulsifiers “X” and “Y”, respectively. The dehydration and demineralization efficiencies of demulsifier “Z” are 2.0 and 7.6%, respectively, higher than demulsifier “Y” and 6.4 and 10.7%, respectively, higher than demulsifier “X” at 50 ppm dosage after 15 minutes of residence time. Demulsifier “Z” also works better on the diluent and bitumen losses to the underflow as compared to demulsifier “X” and “Y”. To find the reason why demulsifier “Z” performs superior to “X” and “Y”, the solids were collected from the original froth and the top, interface, and bottom fractions of the diluted froth for characterization by X-ray diffraction analysis (XRD), X-ray energy dispersive spectrometry (EDS), scanning electron microscopy (SEM), and particle size distribution (PSD). XRD data shows that demulsifier “Z” reduced the amount of clays, iron, and zirconium oxide minerals from the top and interface dilbit fractions as compared to the control sample. PSD data shows that demulsifier “Z” reduced most of the particles of size less than 0.50 µm from the interface. Thus, demulsifier “Z” helps to resolve the interfacial material by separating the minerals that tend to form rag, especially siderite, pyrite, magnetite, rutile and anatase, from the oil/water interface and sends them to the underflow.

Physical and numerical simulations of subsurface upgrading using solvent deasphalting (SSU-SDA) at laboratory conditions will be presented using a heavy crude oil and propane as solvent. In this work, propane flood experiments were carried out in a live crude oil (8.8°API) saturated sand at 120°F and 1000 psi. The results showed oil recovery of 85 wt.% with increases of API up to 14°API for the produced crude oil. Using lab characterization data, a new asphaltene precipitation model was developed that involves four pseudo components to numerically simulate the lab experiments. The pseudo components used are Deasphalted Oil, Heavy Fraction, and Soluble and Solid Asphaltenes. History match showed very good agreement between the experimental and calculated oil and gas rates and cumulative oil. Also, reasonably good match between lab and theoretical API of the produced oils was found throughout the propane flood experiments. Using this model, a field-scale one-well pair in SAGD configuration was simulated for steam only and two steam+ propane cases (10:1 and 1:1 vol. ratio) in a typical heavy crude oil reservoir. Results showed accelerated oil production and higher API crude in the presence of propane in comparison with the steam only case. For the 1:1 steam/propane case, the model predicted that the oil quality improved enough to make the oil transportable through a pipeline. Subsurface upgrading via solvent deasphalting is an innovative concept that has the potential of being a game-changer technology in terms of acceleration of oil production, lower CAPEX and OPEX and environmental benefits. The results presented show the potentiality of SSU-SDA for the exploitation of the vast reserves of heavy and extra heavy oils available in the world.

This paper examines the wettability change during Steam Assisted Gravity Drainage (SAGD) and Expanding Solvent - SAGD (ES-SAGD). The qualitative and the quantitative analyzes of residual oil for steam and steam-solvent coinjection cases are achieved to investigate the impact of clay migration and asphaltene precipitation on wettability alteration. The solvent selection in ES-SAGD is made according to their solubility in asphaltenes; insoluble (n-hexane), soluble (toluene), and intermediate soluble (cyclohexane). Five experiments (one SAGD and four ES-SAGD) are conducted on a Canadian bitumen. Different solvent injection strategies are followed: coinjection and cyclic injection. Wettability is determined through contact angle measurements on the spent rock samples for both inside and outside steam chamber zones. Residual oil saturation is defined via solvent extraction and with a thermal method; Thermogravimetric Analysis (TGA). Two solvents are used for the extraction: toluene and mixture of 90%dichloromethane+10%methanol. The asphaltene fractions of the residual oil samples are further characterized by determining clay content, Solubility Profile; and carbon, hydrogen, sulfur, nickel, and vanadium contents. Both the thermal and the two solvent extraction methods yield more or less the same residual oil saturations. The asphaltene content of the residual oils (22 to 27 wt%) is found lower than the asphaltene content of original bitumen (34 wt%). However, higher metal content is detected on the residual oil asphaltenes. Analysis of residual oil asphaltenes shows a significant presence of clays in the inside steam chamber region for SAGD, which inhibits effective steam chamber propagation by reducing permeability. This asphaltene-clay interaction increases the oil- wetness of the rock surface and impacts the oil production adversely. However, this effect is minimized by the addition of solvents. The wettability measurements on spent rock samples also support these findings. The elemental analysis of asphaltenes reveals that with the increase in precipitation of asphaltenes (for ES-SAGD with n-hexane), there is an increase in vanadium and nickel concentrations. In terms of asphaltene Solubility Profiles, higher polarity was found for asphaltenes originated from inside the steam chamber zone for ES-SAGD with n-hexane, where the effect of n-hexane in the vapor phase is dominant. This work shows that the effectiveness of ES-SAGD may be in part caused by contributions from wettability changes, clay migration, and asphaltene precipitation in addition to by oil viscosity reduction alone. This study provides information on the interaction of clay, asphaltenes, solvent, and steam during SAGD and ES-SAGD. It explains the behavior of clay and asphaltenes during SAGD and ES-SAGD when different solvents are used.

In SAGD (Steam Assisted Gravity Drainage) operations the produced fluids are complex water-in-oil-in-water (W/O/W) emulsions. A diluent is often added to reduce the density and viscosity of the heavy crude oil. However, the quality and composition of the diluents may in some cases increase emulsion stability and cause the dehydration of the oil to be more difficult as there are more surface-active agents added to the oil coming from the diluent streams. To simulate temperature and pressure conditions during SAGD operations, this work studied the effect of three diluents on interfacial rheology of a Canadian heavy oil and synthetic brine at 120°C and 130 psi and then correlated with emulsion stability and oil dehydration. When compared to 25°C, all three diluents exhibited higher higher compressibility at 120°C, while the initial interfacial tension, "phase change" area ratio (area ratio at which the phase change from high compressibility region to low compressibility region), and crumpling ratio (ratio of the compressed surface area to the original area at which the interface starts to collapse) exhibited a more complex behavior. The higher interfacial tension and higher compressibility were correlated with the lower emulsion stability at increasing pressure and temperature in the absence of treating chemicals. Increasing ageing of the film from 10 minutes to 1 hour at 120°C had a similar effect on the three diluents, suggesting the formation of a more elastic film as asphaltenes start to cross-link on the interface. The effect of demulsifiers (emulsion breakers-EB and reverse emulsion breakers-REB) on interfacial was also investigated at RT and 90°C. Demulsifiers that produced the minimum interfacial tension (IFT) with changing concentrations demonstrated to be the best demulsifiers in the bottle tests. A synergistic effect in reducing IFT was found when EB and REB when combined.

Deep tar-mat layers, which occur between the aquifer column and the reservoir-oil column, contain substantial quantities of extremely heavy oil and are found in various parts of the world, most prominently in Middle Eastern nations such as Saudi Arabia, Qatar, south Iraq, and Kuwait. Tar mats are thick layers with oil gravity of less than 10 °API; they isolate conventional oil reservoirs from their aquifers either partially or completely, causing numerous problems when applying oil recovery technology. However, in this study, tar mats are considered as a potential source from which to extract difficult oil. Researchers have attempted to experimentally evaluate the effect of toluene, hot water, and surfactant solution extractions on several carbonate tar-mat rock samples at several different temperatures (25°C, 135°C, 225°C and 315°C). In the study presented in this paper, samples were selected from a tar-mat carbonate reservoir in Kuwait. The physical and chemical geneses of tar-mat oil were analyzed utilizing several experimental geochemical techniques, such as rock evaluation pyrolysis, liquid extracts for Saturates, Aromatics, Resins, and Asphaltenes (SARA analysis), and elemental fingerprinting of Carbon, Hydrogen, Nitrogen, Sulfur, and Oxygen (CHNSO). These geochemical techniques were integrated in order to quantitatively evaluate the tar-mat recovery patterns of the carbonate reservoir at different temperatures. The results showed that the oil recovery significantly increased as the temperature increased. A comparison of all three methods indicates that for light and heavy tar mats, toluene produced the highest oil recovery at all temperatures tested, reaching as high as 47.1% at 315 °C. The surfactant treatment yielded less oil recovery than toluene, which reached as high as 7.5% at 315 °C. The temperature had a significant effect on light tar-mat oil recovery when using water methods; the oil recovery reached as high as 6.2% when using water at 315 °C. However, high-temperature water had little effect on extremely heavy tar mats. The paper provides a systematic method by which to quantitatively characterize tar-mat crudes in carbonate reservoirs.

In situ bitumen recovery directly depends on the reduction of bitumen viscosity. Solvent injection is an alternative to thermal bitumen recovery by steam injection. Injection of solvents containing n-alkanes like butane, propane and naphtha may lead to asphaltene precipitation and deposition in the porous media and a possible negative effect on the ultimate oil recovery. Addition of an asphaltene inhibitor (stabilizer) to solvents is a way to prevent asphaltene precipitation and deposition in a reservoir. Efficiency of an asphaltene inhibitor depends on the characteristics of the inhibitor and bitumen properties.In addition to aromatic hydrocarbons, various natural and synthetic polar heteroatom species can be used as asphaltene inhibitors. Results of the study show that deasphalted bitumen is an effective asphaltene inhibitor and it is of the same strength as environmentally hazardous aromatic hydrocarbons. Resins prevent asphaltene precipitation and are similar to expensive synthetic inhibitors. Addition of less than 8 vol. % of resins to low boiling point n-alkanes provides total asphaltene stabilizationin the process of bitumen recovery. When n-alkanes are used as solvents, it is important to know the amount of precipitated asphaltenes in the reservoir. To obtain such data, an experimental study has been conducted to simulate bitumen recovery. A specially designed experimental set-up was used in the study. The experiments allowed a set of chemical additives to be selected to improve colloidal stability of asphaltenes in bitumen.

During the Steam Assisted Gravity Drainage (SAGD) production process, complex water-in-oil-in-water (W/O/W) emulsions are generated, which need to be treated to promote water-phase separation and recovery of the oil. Due to the similar density of heavy oil and water, dilution is frequently required to improve the separation process, but also to reduce the viscosity of the extracted bitumen to facilitate flow. Although significant research has been carried out to understand the stabilizing and destabilizing factors of both water-in-oil and oil-in-water emulsions, studies related to the characterization of complex W/O/W emulsions containing diluents are still limited. When carrying out this type of analysis, the complex relationship among different variables should be considered, such as the chemistry and concentration of stabilizing agents, water-to-oil ratio and droplet charge. Temperature and shearing methods are process conditions that must be also considered. In this study we combined several techniques to characterize production fluids and synthetic emulsions, using diluents with different composition. Differential Scanning Calorimetry (DSC) was explored as a tool for analyzing the emulsions. Since the oil present in these fluids did not exhibit any thermal transition between -80°C and 30°C, the DSC could be used to quantify the amount of free and emulsified water in one measurement, for either synthetic or produced emulsions. Results demonstrated that this technique has a high potential to characterize emulsified systems with precision, requiring only small amounts of sample and without applying any pre-treatment. The technique can also be used to screen demulsifiers after performing a specific thermal treatment within the equipment. Bottle tests are commonly used in the industry to monitor emulsion behavior. They are easy to perform, but are subject to the judgment of the experimenter, who measures the partitioning of the phases and in some cases their relative opacity. To perform a more quantitative analysis, demulsification was monitored in real-time, using a multiple light scattering device. Phase separation rates were highly influenced by the nature and amount of diluent used and they were correlated with droplet size, interfacial tension and surface pressure measurements. Results were rationalized based on the differences in the asphaltene-resins interfacial film, which will determine the emulsion behavior upon separation in the field when using demulsifiers.

Chemical demulsification is the most widely used method for breaking water-in-diluted bitumen emulsions in oil sands processing. In this paper, the properties and the performance of six intermediates and three blends were investigated. The intermediates and blends were characterized by their relative solubility number (RSN). The results showed that the RSN is an additive property. The dehydration efficiency of the blends was higher than the individual components at the same dosage, indicating there were synergistic interactions among the components on blending. The performance of the demulsifiers was correlated to the interfacial tension (IFT), yield stress of underflow, and bitumen loss to tailings. The equilibrium IFT results did not illustrate any correlation with the performance of the demulsifiers. The yield stress of the underflow, which included settled solids, water, and a rag layer increased with increasing dosage of either intermediate or blend. In addition, the bitumen loss to underflow increased with increasing dosage of either intermediate or blend. The yield stress and bitumen loss to underflow reduced on blending the intermediates. The bitumen loss to underflow increased the size of the aggregates present in the underflow, increasing their immobility and constriction to flow, and eventually a higher yield stress.

Asphaltene is the heaviest and most polar fraction of crude oil that creates many problems in various sections of petroleum industry including reservoir development, well tubing, surface facilities and pipelines. There have been many investigations of the consequences of asphaltene precipitation but the adsorption of asphaltene on rock surfaces and its impact on multiphase flow are not yet well understood. In this work, the effects of asphaltene adsorption on wettability, relative permeability, and displacement efficiency in porous media were evaluated using flow experiments in sand-packs. Clay content and water film residing between pore surface and the hydrocarbon phase are recognized as the governing factors on the level of adsorption. These experiments involved pre- and post-adsorption measurements of relative permeability and recovery in sand packs. Adsorption on sand particles was induced and measured by extended injection of asphaltene solution with known concentration into the sand pack and collection of effluent samples for analysis. A spectrophotometer was employed to measure the asphaltene concentration of each sample and the dynamic adsorption curves were obtained by the subsequent material balance calculations. Adsorption reversibility was examined by analyzing the sand samples at different sections of sand-pack and the wettability alternation was inferred from the displacement behavior. Observed improvement in the displacement behavior is explained by the combined effects of desorption due to brine injection in the post adsorption waterflood and by reduction of interfacial tension due to surface active properties of asphaltene particles. The experimental results show the importance of the existence and properties of water film on the extent of asphaltene adsorption. Presence of clay intensifies the adsorption phenomenon but its impact on two phase flow behavior and recovery depends on the brine salinity. Maximum adsorption occurred under direct contact of sand surface and asphaltene solution when no water film was present, which resulted in more oil-wet conditions, thereby reducing the relative permeability to asphaltene solution and recovery.

In SAGD (Steam Assisted Gravity Drainage) operations the produced fluids are a complex water-in-oil-in-water (W/O/W) emulsion. A diluent, which is a major operational cost item, is often added to the produced fluid to reduce the density and viscosity of the heavy crude, thereby facilitating oil and water separation. The variable quality of the diluent and various types of diluent can increase the emulsion stability and cause the dehydration of the oil to be more difficult as there are more surface-active agents added to the oil from the diluent stream. In this work, the effect of various diluents on interfacial films was studied by measuring interfacial elasticity and "dynamic" surface pressure isotherms and then correlated with emulsion stability and oil dehydration. Compressibility, crumpling film ratio (ratio of the compressed surface area to the original area at which the interface starts to collapse), and surface pressure were determined from the surface pressure isotherms. When interfacial rheological measurements were conducted on fluids treated with the diluent, the system behaved as if a bidimensional gel near its gelation point had organized at the interface. In other words, adsorbed amphiphilic materials such as asphaltenes and resins had self-aggregated at the interface and formed a network, which presents all the rheological characteristics of a gel, acting as a stabilizing mechanism for produced emulsions. When the interface was aged for 20 hrs, its gel strength was nearly 70% higher than the fresh interface, suggesting an explanation why aged emulsions are more difficult to treat. As the surface area of an oil droplet submersed in water is reduced, asphaltene molecules adsorbed onto the interface are drawn closer together and resist compression. This gives information about how rigid the drop surface becomes. The software of interfacial rheological measurements can be set up to capture drop images during compression measurements, allowing us to observe the formation of rigid interfacial skins at the oil-water interface. The amount of skin formed at a droplet surface increased with increasing asphaltene concentration and varied in different diluents. Unlike elasticity and interfacial tension measurements, this method can predict emulsion stability in different diluents and at various asphaltene concentrations. A correlation exists between the interfacial compressibility, crumpling film ratio, and emulsion stability: the higher the crumpling film ratio and the lower the compressibility, the more stable the emulsion. This new test method gives more insights into mechanisms of emulsion stabilization caused by the diluent and asphaltene and potentially can be employed to study the structure and demulsifying performance relationships of EBs (emulsion breakers) and REBs (reverse emulsion breakers).