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• Foam injection in a Hele-Shaw cell, the porous medium, initially saturated with liquid is investigated. • The typically stable process of foam displacing surfactant solution becomes unstable when the foam displaces water, a less viscous fluid, despite the higher viscosity of foam. • The instability is initiated by the immobilization of bubbles dues to the dilution of surfactant concentration from foam-water mixing and subsequent rupture of the film between the bubbles and the solid surface. Foam injection in porous media is desirable for displacing less viscous fluids because of its ability to form a stable front and ensure uniform fluid distribution. In our experimental study, we investigated foam invasion in a radial Hele-Shaw cell initially saturated with either water or a surfactant solution at the same concentration as that of the foam. We report on an unexpected phenomenon whereby the typically stable process of foam displacing surfactant solution becomes unstable when the foam displaces water, a less viscous fluid, despite the higher viscosity of foam. Nevertheless, this instability can be moderated by either reducing the gas fraction in the foam or adding a small amount of surfactant solution to the water. Through single-bubble analysis, we observe that surfactant dilution, resulting from the mixture with water during foam injection, can trigger the rupture of thin films between large bubbles and the surfaces of the Hele-Shaw cell. This leads to the immobilization of larger bubbles, around which smaller bubbles accumulate densely. Such disturbances create side branching and a distinct fingering pattern within the foam flow. From the observations, the foam-water contact line growth follows a L c ∼ t 2 / 3 relation, deviating from the L c ∼ t 1 / 2 growth expected in stable displacement scenarios. [Display omitted] [ABSTRACT FROM AUTHOR]

• Studied single-well huff and puff (cyclic) CO 2 injection and geothermal system. • Cyclic CO 2 -geothermal process realizes CO 2 storage and cumulative energy production. • In each cycle, the shut-in period was beneficial for CO 2 storage. • Process can be tuned between focus on CO 2 storage or geothermal heat harvesting. In this study, a single horizontal well huff and puff (cyclic) CO 2 injection and hot water production system has been investigated to combine CO 2 storage with geothermal energy extraction in the Basal Cambrian Sandstone Unit (BCSU) in the province of Alberta, Canada. The results reveal that the cyclic CO 2 plume geothermal process realizes total CO 2 storage amount and cumulative energy production varying between 10.9 and 100.8 million m3 and 69.1 to 140.2 GWht, respectively. In each cycle, it was found that the shut-in period was beneficial for CO 2 storage. The thermal Energy Produced to Energy Invested (tEPEI) ratios indicate that most cases can be considered as efficient geothermal production systems for heat production. Although cases with the highest CO 2 injection may not be efficient for geothermal energy production, the thermal energy produced from these cases was greater than the compression energy invested for CO 2 injection. This study describes a new option to combine both CO 2 storage and geothermal energy production. [ABSTRACT FROM AUTHOR]

Under the climate change crisis evolving from greenhouse gas (GHG) emissions, society is seeking ways to produce energy with zero or minimal emissions. Currently, carbon capture, utilization, and storage and low or zero emission renewable energy sources are options that are being considered to reach our goals to constrain global warming. Optimal technologies would be those that both sequester GHG and generate energy, for example, combined geothermal energy production with carbon dioxide sequestration. Here, we expand on previous work on carbon dioxide plume geothermal processes where we examine the potential to combine both underground CO 2 sequestration and geothermal energy harvesting from the low temperature (∼100 °C) and low permeability Basal Cambrian Sandstone Unit in Alberta, Canada. In the proposed process, carbon dioxide injection is used to produce hot brine to surface with the goals of keeping the carbon dioxide sequestered while realizing geothermal energy at surface. Consistent with prior work, the results from our study confirm that both CO 2 sequestration and geothermal operation is possible and could have commercial value and environmental benefits. • Net zero greenhouse gas (GHG) emissions energy systems are needed. • Examine combined GHG sequestration and geothermal heat extraction operation. • Geothermal system examined is the Basal Cambrian Sandstone Unit in Alberta, Canada. • CO2 injection used to produce hot water to surface while sequestering all CO2. • Results demonstrate that both CO 2 sequestration and geothermal operation possible. [ABSTRACT FROM AUTHOR]

• Simultaneous consideration of design and schedule optimization for a bitumen upgrader in real time. • Consideration of multiple upgrader configurations and their dynamic changes in design and schedule operations. • Empirical model based optimal decision making for each individual unit per configuration of the upgrader. • Minimizing cost of energy utilization for a bitumen upgrader leading to a lower carbon footprint. • Profit maximization for a bitumen upgrader leading to the increased production of more valuable petroleum fractions. Partial upgrading of bitumen is advantageous yet energy intensive in itself, needing various resources such as electricity, heat, hydrogen, and steam. Therefore, partially upgrading the bitumen while minimizing energy usage and thus lowering the carbon footprint is desirable. Consequently, optimal design and operation of an upgrader then becomes a challenging two-pronged problem. The key, however, lies in identifying that the design and operation problems are not mutually exclusive, but instead, synergistic, and hence require simultaneous consideration. Consequently, this research highlights the importance of the real-time integrated design and scheduling problem through two formulations; maximizing profit and minimizing energy usage. The results indicate changes in design and scheduling decision variables as per the medium-term forecasts of the volatile commodity and energy pricing markets. Therefore, a design independent of the scheduling constraints or a schedule based on a fixed design may lead to suboptimal results in the design and/or schedule decision space(s). [ABSTRACT FROM AUTHOR]

The oil sands mining tailings inventory is growing and current treatment technologies are costly or unable to recover water effectively and handle the high solids content of the waste. Here we consider in-situ treatment of mature fine tailings (MFT) where additives are injected directly into the tailings to consolidate the solids so that the pond area can be reclaimed. This method eliminates the need for a dilution pre-step in the treatment of MFT. In a series of experiments, the impact of additives (iron(III) chloride and polyacrylamide), mixing speed, gas additives, and process scale on the de-watering performance of treated MFT was examined. It was found that the in-situ treatment method resulted in a better tailings product (higher final solids content) than an ex-situ method with ideal mixing conditions. The injected gases contributed to de-watering, chemically (by CO 2 decreasing the pH of the tailings pore water) and physically (by convective mixing). After treatment, a layer of supernatant water continuously accumulates at the top of the tailings layer. The results demonstrate that injection of chemicals into the tailings layer leads to water rejection from the tailings layer leading to a layer with high solid content. [ABSTRACT FROM AUTHOR]

• Steam-Assisted Gravity Drainage (SAGD) stores huge amounts of heat in the reservoir during its operation. • SAGD steam chambers are typically higher than 150 °C when oil production stops. • About one-third of the total injected energy is stored in the reservoir rock. • Heat recovery options include vertical floods of working fluid or cyclic heat removal. In the steam-assisted gravity drainage (SAGD) process, large amounts of steam are injected into the reservoir to mobilize bitumen for its production to surface. The amount of thermal energy injected into the reservoir creates a man-made geothermal system that could be used to yield heat after the SAGD operation is complete. In the research documented here, for the first time, the amount of energy stored in the reservoir is evaluated and potential processes for recovery of the thermal energy are explored. The results reveal that after 10 years of SAGD, about 35% of the total injected energy in the steam remains in the reservoir rock from which the bitumen was extracted. After a 1 year blowdown stage at the end of the SAGD operation, ∼32% of the total injected energy remains in the reservoir rock. Three cases are used to explore the potential for recovering the thermal energy in the reservoir rock. The results show that the best case is one where a new horizontal well is added at the top of the reservoir above the SAGD well pair. In this case, >100 °C water was recovered at high rate for over 1,400 days realizing about 34% recovery of the thermal energy contained in the reservoir rock after the SAGD blowdown stage. The results demonstrate that there is potential for recovering the thermal energy. This recovered energy offers means to make the SAGD process more thermally efficient over its entire energy production life. [ABSTRACT FROM AUTHOR]

Laboratory scale experiments were conducted to obtain insights into factors that influence bacterial transport and deposition in porous media. According to colloidal filtration theory, the removal efficiency of a filter medium is characterized by two main factors: collision efficiency and sticking efficiency. In the case of bacterial transport in porous media, bacteria attached to a solid surface can establish a thin layer of biofilm by excreting extracellular polymeric substances which can significantly influence both of these factors in a porous medium, and thus, affect the overall removal efficiency of the filter medium. However, such polymeric interactions in bacterial adhesion are not well understood and a method to calculate polymeric interactions is not yet available. Here, to determine how the migration of bacteria flowing within a porous medium is affected by the presence of surface-associated extracellular polymeric substances previously produced and deposited by the same bacterial species, a commonly used colloidal filtration model was applied to study transport and deposition of Pseudomonas fluorescens in small-scale columns packed with clean and biofilm coated glass beads. Bacterial recoveries were monitored in column effluents and used to quantify biofilm interactions and sticking efficiencies of the biofilm coated packed-beds. The results indicated that, under identical hydraulic conditions, the sticking efficiencies in packed-beds were improved consistently by 36% when covered by biofilm. [ABSTRACT FROM AUTHOR]

The oil sands resource in Western Canada are a considerable energy asset for Canada, but the energy and emissions intensities of producing this petroleum resource are substantially worse than that of conventional petroleum resources. With requirements for carbon-intensity reduction, new, less emissive recovery processes must be developed to enable continued production and cash flow from this important resource. The largest source of carbon emissions on in-situ in oil sands recovery processes, such as Steam-Assisted Gravity Drainage (SAGD), is steam generation, where natural gas is combusted. An alternative to conventional steam generation is Direct Contact Steam Generation (DCSG), where steam is generated in the combustion flame, and with rich oxygen combustion, the steam plus carbon dioxide mixture is injected into the reservoir. We explore the carbon intensity of DCSG and compare it to existing once-through steam generation using life cycle analysis. The results reveal considerable environmental benefits with nearly 30% emission reduction when applying a DCSG in SAGD instead of an OTSG. The results suggest that oil sands operators could improve their emissions intensity significantly if they adopted DCSGs in their operations. [Display omitted] • In-situ oil sands recovery processes use once-through steam generation (OTSG). • Steam-Assisted Gravity Drainage recovery process has high greenhouse gas emissions. • Direct contact steam generation (DCSG) injects steam + carbon dioxide into reservoir. • Life cycle assessment results demonstrate that DCSG is better than existing OTSG. • DCSG yield nearly 30% reduction of greenhouse gas emissions versus OTSG. [ABSTRACT FROM AUTHOR]

Cold production methods for heavy oil resources in Western Canada yield recovery factors averaging about 10% and as yet, there are no commercially successful technologies to produce oil from these reservoirs with recovery factor greater than 20%. This means that the majority of oil remains in the reservoir. The objective of this study is to determine technically and economically feasible recovery processes for thin heavy oil reservoirs by using a simulated annealing algorithm. The results reveal that high injection pressure is critical to a successful hot water flooding strategy. Also, they show from a thermal efficiency point of view that it is most efficient to adopt an injection temperature profile where the injection temperature starts high earlier in the process and ends at lower water temperature. The lower temperature injection at later stages of the recovery process partially recovers the heat stored in the reservoir matrix and therefore increases the overall heat utilization efficiency. A sensitivity analysis shows that the permeability distribution affects the performance of the hot water flooding process most significantly. The existence of a higher permeability zone in the lower part of the reservoir leads to earlier oil production and water breakthrough. High permeability was found to lead to more oil and water production in the early stage of operation and achieved the best economic performance. The low permeability case exhibited relatively low oil production volume. Although it has the lowest cumulative injected energy to oil produced ratio, poor oil production renders the operation process uneconomic. Given the volume of currently inaccessible thin heavy oil resources, the optimized strategies developed here provide important guidelines to convert these resources to producible reserves. [ABSTRACT FROM AUTHOR]

Biofilm formation in natural and engineered porous systems can significantly impact hydrodynamics by reducing porosity and permeability. To better understand and characterize how biofilms influence hydrodynamic properties in porous systems, the genetically engineered bioluminescent bacterial strain Pseudomonas fluorescens HK44 was used to quantify microbial population characteristics and biofilm properties in a translucent porous medium. Power law relationships were found to exist between bacterial bioluminescence and cell density, fraction of void space occupied by biofilm (i.e. biofilm saturation), and hydraulic conductivity. The simultaneous evaluation of biofilm saturation and porous medium hydraulic conductivity in real time using a non-destructive approach enabled the construction of relative hydraulic conductivity curves. Such information can facilitate simulation studies related to biological activity in porous structures, and support the development of new models to describe the dynamic behavior of biofilm and fluid flow in porous media. The bioluminescence based approach described here will allow for improved understanding and control of industrially relevant processes such as biofiltration and bioremediation. [ABSTRACT FROM AUTHOR]

Highlights: [•] Steam-Assisted Gravity Drainage is process of choice for extra heavy oil recovery. [•] Average recoveries from heavy oil and oil sand reservoirs are typically low. [•] Some SAGD operations are actually not net energy generating. [•] New oil sands processes needed to improve energy and carbon dioxide intensities. [ABSTRACT FROM AUTHOR]

Highlights: [•] Low temperature oxidation (LTO) region was divided into four different subzones. [•] Kinetic parameters have been calculated for each subzone of LTO. [•] Activation energy was positive for two subzones and negative for the other two. [•] Elemental ratios of LTO residues provide insights for product sequence estimation. [•] Product sequence and kinetic parameters are instrumental for numerical modeling. [ABSTRACT FROM AUTHOR]

Nunavut is a territory in Northern Canada partially within the Arctic Circle. Currently, diesel is the fuel of choice for both power and heating. Previous studies (Das & Cañizares, 2016; Hazelton, 2019) have shown that hybrid renewable energy models are feasible alternatives for electricity generation from economic, technical, and environmental perspectives. However, Marin (2015) shows that there is also a social perspective needed to build agreement among the diverse set of stakeholders, without which new energy solutions are unlikely to be implemented. This study examines the existing and potential low carbon energy sources in Nunavut that could possibly replace diesel; those available now (wind, solar), those not yet affordable (hydroelectric, geothermal) and those with hurdles still to be addressed (tidal, biomass, nuclear). The interplay of stakeholder acceptability criteria and roadblocks is highlighted in the context of one household in Iqaluit. Our findings show that the subsidized price of diesel-based electricity and the lack of grants for renewable options, offer little financial incentive for bottom-up change. While conflicting priorities between existing and potential power producers stall top-down change. The Government of Nunavut should remove the roadblocks that prevent individuals from participating in distributed energy generation, and lobby for the development of Nunavut's vast tidal energy potential as a critical component of Canada's net-zero emissions goal by 2050. In the meantime, given that there are currently no acceptable alternatives for diesel-based heating either, it becomes clear why it continues to be so difficult to replace diesel in Nunavut. • Nunavut, a territory in Northern Canada, relies on diesel for power and heating needs. • Diesel generates greenhouse gas emissions and imparts large costs for energy. • Examined low carbon energy sources for application in Nunavut to replace diesel. • Solar generated electricity with net metering is only current practical option. • A lack of financial incentives and conflicting priorities hinder the adoption curve. [ABSTRACT FROM AUTHOR]

Abstract: Steam-Assisted Gravity Drainage (SAGD) is a key in-situ recovery process being used today to extract oil from bitumen reservoirs. In SAGD, an oil-depleted chamber of steam grows within the oil sands formation along a pair of horizontal wells and heats bitumen-laden oil sands at its edge. The viscosity of bitumen drops by up to five orders of magnitude when heated to above 200°C and mobilized bitumen at the chamber edge flows under gravity to a production well located at the base of the chamber. If the steam chamber does not grow uniformly along the wellpair, then bitumen recovery is less than ideal. To raise the thermal efficiency, and consequently the economics, of the process, efficient heat transfer from chamber to the oil sands must occur and the chamber must grow uniformly along the entire length of the wellpair. If steam fingers develop at the edge of the chamber, then the heat transfer area enlarges and raises the thermal efficiency of the process since more heat is directed to the oil sands. In this research, the stability of the interface between the steam chamber and oil sands is examined by using linear stability theory. The results show that the stability is controlled by the difference between the energy content-weighted Darcy–Rayleigh numbers of the steam/water phases (displacing fluid) and the oil phase (displaced fluid). Also, the results show that at typical SAGD steam saturation temperatures, the chamber edge is unstable providing the steam quality at the edge exceeds about 50%. [Copyright &y& Elsevier]

Abstract: Steam-assisted gravity drainage (SAGD) is a mature commercial heavy oil and bitumen recovery technology operated by over 10 operators in Athabasca and Cold Lake reservoirs in Alberta. Initially, in Athabasca reservoirs, the in situ oil phase viscosity typically exceeds 1 million cP, yet with heating to over 200°C, the viscosity drops to between 1 and 20cP. The process consists of two parallel horizontal wells: the top one injects steam into the reservoir while the bottom one collects mobilized oil and produces it to the surface. The process is made more thermally efficient by maintaining a liquid pool that surrounds the bottom production well and prevents escape of steam from the steam chamber. This is often referred to as steam-trap control. In field practice, the continued existence of the liquid pool is monitored by examining the temperature difference, known as the interwell subcool, between the injected steam and produced fluids. Typically, the subcool is maintained between 20 and 40°C. Given that there are non-uniformities of the reservoir properties in the downwell direction, there is potential for loss of steam-trap control at one or more locations along the wellbore. In this study, the impact of subcool on the thermal efficiency and performance of SAGD is examined by detailed 3D reservoir simulation. The results show that there is a critical subcool value below which the steam trap fails. [ABSTRACT FROM AUTHOR]

Abstract: About one-quarter of the 1.7trillion barrels of bitumen resource located in Alberta, Canada is hosted in thin reservoirs with thickness less than about 10m and is at this time considered inaccessible by current commercial recovery processes such as Steam-Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation. SAGD is effective at recovering heavy oil and bitumen in reservoirs greater than about 15m thickness but under this thickness, heat losses from the steam depletion chamber are too large and the energy efficiency of the process suffers. Since a large amount of steam is used per oil unit volume produced, this implies large amounts of natural gas combustion which also implies large amounts of carbon dioxide emitted per unit oil volume produced. Thus, thermal processes in thin pay are not energy efficient and produce excessive amounts of flue gases per unit oil volume produced. Solvent additives injected with steam, as done in Expanding-Solvent SAGD (ES-SAGD), can improve oil production rates or at least maintain similar oil production rates with reduced steam injection. The central idea is that steam plus solvent is better than steam alone to mobilize heavy oil in the reservoir. This implies that ES-SAGD can potentially use less water and require smaller water handling and treatment facilities than that in SAGD. Also, the operating temperature is lower than in steam-only processes so that heat losses are reduced and potentially ES-SAGD could be productive in thin reservoirs. In this research, the solvent injection pressure and volume fraction are designed for a single wellpair ES-SAGD operation by optimizing the net energy injected to oil ratio in a detailed and realistic, three-dimensional, heavy oil reservoir. The results show that the operating pressure and injection strategy can be controlled in a sequence that provides high energy efficiency and solvent recovery. [ABSTRACT FROM AUTHOR]

Abstract: In the Expanding-Solvent Steam-Assisted Gravity Drainage (ES-SAGD) process, solvent added to injected steam mixes with the oil at the edge of the depletion chamber to help reduce the viscosity of the oil phase below that which would result with steam alone. In this gravity drainage process, the key to heavy oil and bitumen production is the mobility of the oil phase which is controlled largely by the viscosity of the oil phase. In ES-SAGD, injected solvent can be used to substitute for steam and thus yield a more environmentally friendly recovery technology because the amount of flue gases emitted is lowered because less steam is required. It is not completely clear at what values the pressure and temperature of the depletion chamber should be maintained at to yield optimum production of oil and solvent. The higher the pressure, the higher the corresponding saturation temperature and the lower the viscosity of the oil phase. Also, the higher the pressure, the higher the solubility of solvent in the oil phase and the lower the viscosity of the oil phase. However, the higher the pressure, the higher the corresponding saturation temperature, and depending on the relative roles of pressure and temperature, the solubility of the solvent can be higher or lower. This means that there is a complex relationship between the operating pressure and its corresponding saturation temperature, the solubility of solvent, and the viscosity of the oil phase. In this research, the steam and solvent injection strategy is examined by viewing process trajectories on the pressure versus temperature diagram. After the process is visualized on these phase diagrams, the operating strategy required to maximize oil production and minimize the cumulative steam-to-oil ratio becomes clearer. [Copyright &y& Elsevier]

Despite technical and economic success of Steam-assisted gravity drainage (SAGD), improvements of its thermal efficiency as reflected by the steam-to-oil ratio (SOR) present challenges. Given that the SOR is a measure of the ratio of the energy invested to the energy (chemical energy in oil) produced and emissions intensity, there is strong motivation to reduce the SOR since the lower the SOR, the lower is the energy invested and emissions produced per unit oil produced. However, there appears to be few directions for modifying SAGD to improve the SOR by adjusting the steam injection strategy or fluid production strategy alone. In this research, multiple steam components and multiple bitumen components are used in a thermal reservoir simulation model to understand the time scales of steam flow and bitumen mobilization, drainage, and production. The results reveal that immediate bitumen response is observed near the well and in the steam-trap liquid pool above the production well whereas the time scale between steam stimulation and bitumen response can be as high as hundreds of days. This brings into question the meaningfulness of the steam-to-oil ratio as a control variable for behaviours far from the well pair. • Steam-Assisted Gravity Drainage (SAGD) has multiple time scales. • Time scale for steam flow in the reservoir can be immediate to 100s of days. • Time scale for bitumen mobilization, drainage, and production is up to 100s of days. • Time between steam stimulation and consequent bitumen response can be separated by 100s of days. [ABSTRACT FROM AUTHOR]

In this study, a hybrid convolutional-recurrent neural network (c-RNN) is evaluated for making predictions of the five-year cumulative production profiles in multistage hydraulically fractured wells. The model was trained by using a combinations of completion parameters, rock mechanical properties, and well spacing and completion order for each stage of 74 wells in the Montney Formation in Alberta. The prediction accuracy of the various combinations was measured by using the mean average percent error and mean absolute error generated through the leave-one-out method. The best combination of inputs was found to be the rock mechanical properties surrounding each perforation cluster, the proppant amount used for every stage, and the spacing and completion order of neighboring wells. The novelty of this study is that the input variables used are at the stage level rather than the average of the entire well. The accuracy of the model was found to increase exponentially as the production of multiple wells was aggregated. The approach yields insights for planning new well drills in fields with existing development since it provides the ability to run multiple field development scenarios without having to spend capital. • Multistage hydraulically fractured (MHF) well performance prediction is challenging. • Machine learning-based model developed to predict production profiles of MHF wells. • Variables include geomechanics, fluid-proppant transport, geological heterogeneity. • Method uses completion variables and rock mechanical properties. • Model accuracy increases exponentially when multiple well data is aggregated. [ABSTRACT FROM AUTHOR]

Fractured oil reservoirs are a major source of petroleum globally but recovery from them is extremely challenging. Extensive research is carried out to improve oil recovery from fractured reservoirs by using water, surfactant and polymer solutions and up to some extent nanofluids flooding but no significant success is achieved. Aim of the research documented here is to examine the impact of different concentrations of nanofluids on the displacement of oil from a thin gap and to understand the behavior of the interfaces by studying the interfaces on both macro and micro scales, and by examining variation in the relative permeabilities, mobility ratios and capillary numbers. 1 wt% and 2 wt% of CNC nanofluids are flooded at different flow rates to recover mineral oil from a thin gap in a Hele-Shaw cell. Results for each concentration is compared with each other as well as with the water flooding system. It was observed that 2 wt% concentration nanofluids creates a stable interface resulting in an enormous increase in the oil recovery (piston like displacement) i.e., up to 98%. Microscopic analysis of the interfaces reveals that the nanofluid penetrates the oil phase forming a microemulsion upstream of the main interface. The results could be helpful for flooding design consideration to improve oil recovery from the fractured reservoirs. • Oil recovery and interfaces of CNC & oil are evaluated both on macro and micro scales. • CNC increased viscosity, decreased interfacial tension and controlled mobilities. • 1 wt % displaced about 4% more oil than water. • 2 wt% CNC nanofluids did piston like displacement of oil and recovery is upto 98%. • CNC nanofluids could be effectively used for recovery from fractured reservoirs. [ABSTRACT FROM AUTHOR]

• Naphthenic acids (NAs) present adverse effects to environment, organisms and refining. • Review separation of NAs from crude oil and oil sands process-affected water (OSPW). • Mechanisms of NAs separation techniques provided. • More efficient catalysts and ionic liquids should be considered for NA separation. • Electrochemical and regenerable adsorbents suggested to separate NAs from OSPW. Naphthenic acids (NAs) are widely present in crude oil and oil sands process-affected water (OSPW). NAs in crude oil lead to corrosion problems, promote emulsion formation, decrease oil quality, and deactivate catalysts, making it critical to isolate NAs. Owing to their toxicity and recalcitrance, the existence of NAs induces serious environmental problems and is the primary target for treating OSPW. The current review provides a summary on the properties and adverse effects of NAs and compares existing techniques to separate NAs from crude oil and OSPW. The mechanisms of these approaches as well as limitations are described. Given the environmental impacts of NAs, new, more effective technologies for extracting and treating these materials must be found. [ABSTRACT FROM AUTHOR]

Environmental and economic impacts of methane escaping from the natural gas supply chain remain uncertain. Flowback emissions from hydraulically fractured natural gas wells are a key component of emissions from unconventional gas wells. While reduced emission completions in the United States are required by regulation, Canada’s proposed regulation will only be implemented in 2020 with the two highest producing provinces under exemption. To understand potential benefits of regulations, we use predictive modelling of well-level production data of 1633 hydraulically fractured shale gas wells in five plays to estimate pre-production emissions. The mean estimate for flowback emissions (2346 ± 95% confidence interval of 91 Mg CO 2 e/completion) fall within the 95% confidence limits of measured potential emissions (2566 ± 777 Mg CO 2 e/completion). Our results indicate that in 2015, the average emissions per shale gas well undergoing flowback was 2347 Mg CO 2 e/completion in the U.S. and 1859 Mg CO 2 e/completion in Canada. Mean potential profits from controlling methane emissions using reduced emission completions were US$17,200/well in the U.S. and US$11,200/well in Canada. [ABSTRACT FROM AUTHOR]