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Abstract Oils that are potential candidates for in situ combustion recovery processes are often screened by means of their oxidation characteristics: in particular, the kinetics of the ignition process and the transition from low-temperature to high-temperature oxidation through what is known as the "negative temperature gradient region". These characteristics are readily studied in ramped-temperature oxidation tests, which involve the controlled heating of recombined, oil-saturated cores in a one-dimensional plug flow reactor under a flowing stream of air (or oxygen-containing gas). The purpose of these tests is to study the global oxidation behavior and reaction kinetics under controlled conditions, with the end purpose of providing realistic data for incorporation into a numerical simulator which can he used to predict field performance. A ramped-temperature oxidation apparatus was used to conduct a detailed, two-year parametric study of the oxidation characteristics of Athabasca Oil Sands bitumen. The test matrix involved various levels of pressure gas injection rate, oxygen content of the injected gas and maximum ramp temperature. This paper details the principal findings for the 45-test study: in particular, the need to maintain high reaction temperatures >380 C) in order to mobilize and produce heavy oils under conditions of dry in situ combustion. Design considerations and operational guidelines for successful field projects which can be suggested from the results of this study are also discussed. Introduction In order to successfully exploit the vast potential of processes based on the injection of air or an oxygen-containing gas for the recovery of conventional and heavy oils, it is necessary to understand the nature of the oxidation reactions which are involved. The traditional concept of in situ combustion, which is based on the high-temperature combustion of a coke-like fuel, will not explain the combustion behavior which is observed in many field projects or even in laboratory combustion tube experiments. For this reason, a number of experiments have been developed which concentrate on the global oxidation kinetics. These studies normally involve exposing the crude oil to a programmed rate of heating while in contact with the oxidizing gas. The oxidation kinetics are then observed using effluent gas analysis techniques, and differential thermal techniques such as the differential thermal analysis (DTA) work of Vossoughi et al., the pressurized differential scanning calorimetry (PDSC) studies of Phillips et al., and Belkharchouche and Hughes and the accelerating rate calorimetry (ARC) technique of Yannimaras et al. Previous investigations of the oxidation reactions which occur during in situ combustion processes have shown the existence of at least two temperature ranges over which the oxygen uptake rates are significant. While Kisler and Shallcross have reported that the light (40.2 API) Australian oil which they studied exhibited at least three temperature ranges over which localized maxima in the oxygen uptake rate were observed, the majority of heavy oils for which oxidation data have been reported exhibit only two distinct local maxima in the oxidation rates. For convenience, the two temperature ranges where elevated oxygen uptake or energy generation rates are observed are denoted as the low-temperature oxidation and high-temperature combustion regions. For heavy oils, the range of temperatures associated with the low-temperature oxidation region is roughly from 150 to 300 C, while the high-temperature combustion region generally corresponds to reaction temperatures in the range from 380 to 800 C. The transition temperature range which falls between the temperatures corresponding to the low-temperature oxidation and high-temperature combustion regions is characterized by reduced oxygen uptake and energy generation rates. The lower temperature portion of this transition range in which the oxygen uptake and energy generation rates decrease with increasing temperature is the "negative temperature gradient region". The significance of this region will be more fully explored in the following sections of this paper. Description of Test Procedure Equipment The ramped-temperature oxidation apparatus and test procedures have been described in detail by Moore et al. The apparatus essentially consisted of a plug flow reactor with an inside diameter of 22.1 mm and an inside length of 320.7 mm. The reactor was equipped with five Inconel-sheathed Type K thermocouples which were spaced 50.8 mm apart and inserted radially to the centerline of the core. The reactor was mounted in an aluminum beating block which was equipped with strap heaters. Temperature control and monitoring were achieved using an in-house developed computer-based system. A mass-flow meter controlled the oxidizing gas injection rate and a backpressure control valve maintained the desired operating pressure at the reactor outlet.

A highly unconsolidated undersaturated reservoir producing heavy oil with an API of 12.1° is located in Lindbergh Field of Elk Point area, Alberta, Canada. A specific well in this reservoir was initially designed to produce oil via a cold heavy oil production with sand (CHOPS) mechanism. However, a large amount of the sand production on a daily basis plugged the progressive cavity pump installed in the well. The cost of well services to unplug the pump on a monthly basis exceeded the revenue from produced oil, and thus, the well was considered uneconomic. Various techniques have been sought to control the sand production and to increase the cumulative oil production and the pump efficiency. Installing screens and meshes in the production interval of the wellbore was analyzed as a solution to the sand production. Installing screens increased the skin factor and resulted in a very low production rate of 0.15 m3/day. The cost of purchasing and installing screens was estimated to be approximately $87,650 with five shut-in days. In addition, the screens also needed further sand clean up, which is an expensive process. Hence, the screens were not recommended for this candidate well. A Back-pressure regulator (BPR) is currently installed on the casing of the well. The initial purpose of installing BPR on the casing was to control the wellbore pressure. The BPR restricts the flow of gas vented through the casing-tubing annulus. This study analyzes the effects of restricting flow of the vented gas such as solution gas reduction, which causes (i) higher settling velocity for the sand grain, (ii) lower Basic sediment and water (BS&W), and (iii) lower in situ oil density. The production data of candidate well obtained from AccuMap (v.18.12) shows that the production hours increased significantly after installing BPR. This is because the number of well services reduced by 90 %. This results in an approximately $34,000 per month increase in profit (assuming $30.00/barrel of oil) for each well. This shows one million dollars savings on a monthly basis when the application of the BPR installation is implemented on 30 similar wells. The cost of the BPR installed on well is $328.00, and there is no operating cost involved since the cost of additional, necessary maintenance and operation is nearly negligible. Moreover, this study provides the field examples of improper BPR operation, which resulted in economic loss. Possible solutions to fix the improper installation of BPR are proposed as well.

In this paper, new optimal power flow (OPF) techniques are proposed based on multiobjective methodologies to optimize active and reactive power dispatch while maximizing voltage security in power systems. The use of interior point methods together with goal programming and linearly combined objective functions as the basic optimization techniques are explained in detail. The effects of minimizing operating costs, minimizing reactive power generation, and/or maximizing loading margins are then compared in both a 57-bus system and a 118-bus system, which are based on IEEE test systems and modeled using standard power flow models. The results obtained using the proposed mixed OPFs are compared and analyzed to suggest possible ways of costing voltage security in power systems.

The life cycle Greenhouse Gas (GHG) emissions associated with the production and use of transportation fuels from conventional and unconventional fossil fuel sources in Canada and the USA are investigated. The studied pathways include reformulated gasoline and low sulphur diesel produced from oil sands, oil shale, coal and natural gas, as well as reference pathways from conventional crude oil. A comparison of Life Cycle Assessments (LCAs) completed for these fuels indicates considerable uncertainty in these emissions, illustrating the need for further LCAs with particular attention to completeness and transparency. Based on the considered studies, only one unconventional pathway has better GHG emissions performance than the conventional pathways: Fischer-Tropsch diesel from natural gas. However, the limitations of the data used here and other factors that may restrict a switch to natural gas must be considered. Furthermore, there are considerable opportunities to reduce emissions from the unconventional pathways.

Abstract CO2-EOR, combined with multi-stage fractured horizontal wells has been considered as the most promising and environmentally-friendly technique for unlocking tight oil resources (Ghaderi et al., 2013). With more than 2,500 horizontal wells drilled into the Cardium formation within the Pembina field (CDL, 2016), adapting and utilizing existing wells and infrastructure for future CO2-EOR development is economically attractive. Nevertheless, the drilling, completion and hydraulic fracturing design and practices can vary greatly as a result of different geological conditions, operator preference and technology advancements through the years. This paper presents an effective workflow that selects hydraulically fractured horizontal wells suitable for CO2-EOR in consideration of both reservoir and completion qualities. The process of identifying refracturing candidates and potential risk associated with CO2-EOR performance is also developed. Two groups of parameters - the reservoir quality group (remaining oil in place, permeability, reservoir depth and a fluid type) and the completion quality group (well lateral length, well spacing, fracture spacing, SRV and a skin factor) - are first defined. A fully compositional simulator is applied to study the effects of these parameters on reservoir responses to CO2 injection. A Fuzzy Analytic Hierarchy Process (F-AHP) is then employed to rank candidate horizontal well pads for CO2-EOR. The ranking results and simulated oil recovery factor for each candidate show significant agreement. In addition, with the help of crossplots, the horizontal wells with below-average completion quality, but relatively good reservoir quality, are selected as refracturing candidates. A risk analysis reveals that the presence of conglomerate on the top of the Cardium formation plays a significant role, resulting in upward moving of CO2 and hence a lessened chance of contacting and displacing oil contained in the lower sands. Additionally, permeability heterogeneity has an adverse effect on CO2 sweep efficiency and can add uncertainty to the success of a recovery process. These factors should be further evaluated after the initial screening process.

Membrane-free redox cell with no mass transfer between anode and cathode chambers.

The goal of this paper is to develop models for estimating the potential profit of a battery storage system that provides multiple services in a competitive electricity market. We assume the size of the battery is small relative to the energy market volume and its actions do not impact the energy market outcomes; thus, it is a price-taker in the energy market. However, considering the relatively smaller market volume for ancillary services, we consider the battery’s strategies to impact the outcomes of the markets for frequency regulation service, spinning reserve, and non-spinning reserve. An optimization model is proposed considering the uncertainties in energy prices, the offers of ancillary services by competitors, and the energy deployment in ancillary services markets. We employ robust and stochastic optimization approaches to account for the different nature of each uncertain variable. The scheduling is done in day-ahead and is later refined closer to real time. Numerical results are provided based on real-life data.

Abstract In this article, the novel concept of using magnetic nanofluidic electrolyte for redox flow batteries is demonstrated for the first time. In this regard, the stable magnetic nanofluidic electrolytes are prepared by dispersing magnetic modified multiwalled carbon nanotubes (MMWCNTs) in the positive electrolyte of a polysulfide-iodide redox flow battery at mass concentrations of less than 0.3 g L−1. The electrochemical behavior of magnetic nanofluidic electrolyte was examined using cyclic voltammetry at different mass concentrations of MMWCNTs with a carbon felt electrode. Higher and stable peak current densities were observed at larger mass concentrations of MMWCNTs. A polysulfide-iodide redox flow battery was employed to evaluate the influence of magnetic nanofluidic electrolyte on the battery performance for various mass concentrations, velocities of flowing electrolyte, and current densities using electrochemical impedance spectroscopy, polarization, and galvanostatic charge-discharge experiments. A decrease in ohmic resistance as well as reductions in the charge-transfer and mass-transfer resistances were observed for the magnetic nanofluidic electrolyte compared to those obtained in the absence of MMWCNTs. Adding MMWCNTs to the positive electrolyte at the mass concentration of 0.3 g L−1 results in enhanced performance of the polysulfide-iodide redox flow battery, whereby the peak power density increases by 45% and an energy efficiency of 79.91% was obtained at a current density of 20 mA cm−2. Moreover, high coulombic efficiency close to 100% and stable cycling performance over 200 cycles were achieved using magnetic nanofluidic electrolyte. After 50 cycles, at a current density of 30 mA cm−2, the energy efficiency of the battery operated with magnetic nanofluidic electrolyte remains 10% greater than that obtained in the absence of MMWCNTs. Besides improving the battery performance, MMWCNTs can be separated and recovered using magnetic decantation during electrolyte replacement for redox flow batteries involving high capacity fade and precipitation, which preserves system cost-benefits. The magnetic nanofluidic electrolyte could be applied for different redox solutions using appropriate magnetic nanoscale conductors. This innovative concept opens up a new opportunity to develop the next generation of high-performance and low-cost flow batteries.

Abstract The dissolution of carbon dioxide (CO 2 ) in deep saline aquifer water is recognized as one of the fundamental mechanisms in the subsurface for storing significant quantities of CO 2 . One fundamental physical effect of CO 2 dissolution is the slight increase in water density in the layer in contact with the buoyant free-phase CO 2 plume. Under specific conditions, this may lead to gravitational instability and the onset of free convection, significantly accelerating the dissolution of the free-phase CO 2 by bringing CO 2 in contact with a larger volume of aquifer water. It is also feasible to enhance CO 2 dissolution using engineering methodologies such as injecting water on top of the plume of CO 2 . The objective of this review is to provide a perspective on the progress in modeling and experimental observations of physical aspects of CO 2 dissolution in deep saline aquifers. We review the published research efforts concerning the physical effects of CO 2 dissolution in formation water, the conditions under which process can be accelerated either naturally, such as by free convection, or by use of engineering methodologies, and the effects of CO 2 dissolution on CO 2 storage. Finally, we discuss areas in need of further research.