Oil Sands Production Research Articles

Ozone in the boreal forest in the Alberta Oil Sands Region

Abstract. Measurements of ozone were made using an instrumented tower and a tethersonde located in a forested region surrounded by oil sands production facilities in the Athabasca Oil Sands Region (AOSR). Our observations and modeling show that the concentration of ozone was modified by vertical mixing, photochemical reactions, and surface dry deposition. Measurements on the tower demonstrated that when winds are from the direction of anthropogenic emissions from oil sand extraction and processing facilities, there is no significant increase in ozone mixing ratio compared to when winds are from the direction of undisturbed forest. This suggests that ozone is destroyed by reaction with NOx from oil sands extraction operations (as well as NO resulting from photolysis of NO2). Vertical gradients of ozone mixing ratio with height were observed using instruments on a tethered balloon (up to a height of 300 m) as well as a pulley system and two-point gradients within the canopy. Strong gradients (ozone increasing with height near 0.35 ppb m−1) were measured in the canopy in the evening and overnight, while morning and daytime gradients were weaker and highly variable. A 1D canopy model was used to simulate the diurnal variation of the in-canopy gradient. Model results suggest an ozone dry deposition velocity between 0.2 and 0.4 cm s−1 for this location. Sensitivity simulations using the model suggest that the local NO concentration profile and coefficients of vertical diffusivity have a significant influence on the O3 concentrations and profiles in the region.

Research and Practice of Heavy Oil Hydraulic Pump Lifting Technology in Bohai Bay K Oilfield

In the early stage of heavy oil reservoir development in Bohai Bay K Oilfield, crude oil viscosity is high, conventional lifting processes have poor adaptability, and production energy consumption is high; Entering the stage of ultra-high water cut development, the company implemented carbon dioxide huff and puff, the difficulties in lifting matching brought about by the integrated wellbore requirements of injection and production, high gas-liquid ratio lifting, and enhanced corrosivity of the produced fluid. It conducted research on concentric dual/single pipe hydraulic lifting technology for heavy oil reservoirs, and conducted field practice. The research results and field practice show that the hydraulic pump lifting technology has good adaptability for both heavy oil sand production wells and heavy oil carbon dioxide huff and puff wells, effectively reducing the energy consumption of heavy oil lifting, significantly extending the pump inspection cycle of heavy oil sand production wells, significantly improving the lifting adaptability of carbon dioxide huff and puff wells, and has high promotion value in similar reservoirs and single wells.

Electrochemical degradation of dissolved organic matters in oil sands process water using continuous-flow packed bed electrode reactor

In this study, a continuous-flow packed bed electrode reactor (PBER) was presented for the first time to reclaim oil sands process water (OSPW) generated during the bitumen extraction of oil sands surface mining. The PBER was constructed based on a traditional two-dimensional electrode system (2-DES) by packing pretreated spherical activated carbon (SAC) between the anode and cathode, forming the third electrode, charged and polarized under the electric field. The electrochemical treatment effect of three essential control factors, including cell voltage, electrode space, and flow rate, were investigated on the degradation of dissolved organic matters (DOMs) in OSPW. Electrolysis for 180 min under obtained optimal conditions: cell voltage 10 V, electrode space 6 cm and flow rate 5 mL/min, achieved 74.49% COD and 65.85% DOC removal percentage in PBER compared with only 11.72% and 12.97% achieved in 2-DES at similar conditions. The energy consumption and current efficiency were also significantly improved from 12.29 to 2.21 kW·h/g COD and 9.81% to 54.59%, respectively, thanks to the application of the third electrode. Further analysis revealed that the naphthenic acids (NAs), the primary source of acute toxicity in OSPW, were effectively degraded during PBER electrolysis, which was also validated by the Microtox® test that showed no acute toxicity in the PBER-treated OSPW, indicating that PBER could significantly improve the OSPW's biodegradability. This study first demonstrated that PBER was a prospective technology for process water recycling in oil sands production and tailings ponds reclamation, particularly compared to the traditional 2-DES electrolysis.

Last Barrel Standing? Confronting the Myth of “High-Cost” Canadian Oil Sands Production

Last Barrel Standing? Confronting the Myth of “High-Cost” Canadian Oil Sands Production

Probing the Interfacial Forces and Surface Interaction Mechanisms in Petroleum Production Processes

Despite the advances that have been made in renewable energy over the past decade, crude oil or petroleum remains one of the most important energy resources to the world. Petroleum production presents many challenging issues, such as the destabilization of complex oil–water emulsions, fouling phenomena on pipelines and other facilities, and water treatment. These problems are influenced by the molecular forces at the oil/water/solid/gas interfaces involved in relevant processes. Herein, we present an overview of recent advances on probing the interfacial forces in several petroleum production processes (e.g., bitumen extraction, emulsion stabilization and destabilization, fouling and antifouling phenomena, and water treatment) by applying nanomechanical measurement technologies such as a surface forces apparatus (SFA) and an atomic force microscope (AFM). The interaction forces between bitumen and mineral solids or air bubbles in the surrounding fluid media determine the bitumen liberation and flotation efficiency in oil sands production. The stability of complex oil/water emulsions is governed by the forces between emulsion drops and particularly between interface-active species (e.g., asphaltenes). Various oil components (e.g., asphaltenes) and emulsion drops interact with different substrate surfaces (e.g., pipelines or membranes), influencing fouling phenomena, oil–water separation, and wastewater treatment. Quantifying these intermolecular and interfacial forces has advanced the mechanistic understanding of these interfacial interactions, facilitating the development of advanced materials and technologies to solve relevant challenging issues and improve petroleum production processes. Remaining challenges and suggestions on future research directions in the field are also presented.

Influence of Sand Production Damage in Unconsolidated Sandstone Reservoirs on Pore Structure Characteristics and Oil Recovery at the Microscopic Scale.

Unconsolidated sandstone reservoirs have low rock strength and are easily damaged by sand production. To evaluate the effect of the microscopic pore system on the degree of recovery and sand production damage, five typical unconsolidated sandstone core samples were selected. The nuclear magnetic resonance T2 spectrum of the water-flooding experiments was used to analyze the oil displacement mechanism and sand production damage of the pore throat structure, and the control mechanism of the injection parameters was used to evaluate the recovery and sand production damage degree. The results showed that the recovery of the unconsolidated sandstone core samples was the highest when the injection volume was 6 PV, and the overall pore throat recovery increased from 14.37 to 48.72%. The recovery and sand production damage increased with increasing injection pressure. The overall pore throat recovery was the highest when the pressure was 20 MPa (48.42%), and the sand production damage index was the maximum when the pressure was 25 MPa (19.98%). Under a lower injection pressure, sand production damage mainly originates from loose sand. The main target of loose sand production damage is a smaller pore throat, and the sand production index increases slowly. The recovery increased with the pressure and increased relatively quickly. Under a higher injection pressure, sand production damage mainly comes from loose sand and skeleton sand, causing damage to both smaller and larger pore throats. The sand production damage is positively correlated with injection pressure. The recovery slows down with an increase in pressure or even decreases.

Integration of data-driven models for dynamic prediction of the SAGD production performance with field data

Steam-assisted gravity drainage (SAGD) is a successful thermal recovery process and has been widely applied to oil sands production. The prediction of oil production of the SAGD process plays a significant role in decision-making, where numerical simulation is one of the tools which support engineers. However, the traditional numerical simulation process for the SAGD production prediction, such as history matching, sensitivity analysis, and predictive runs, is a time-consuming process that is always associated with heavy computational costs. Engineers require reliable alternative modeling tools for the management of SAGD production. In this study, a data-driven model-based workflow is formulated and tested for the prediction of the SAGD production performance. After a series of data processing and integration of real field data, the machine learning algorithms are successfully utilized to predict future production performance based on past production information and operational conditions. A comparison of different machine learning algorithms shows that a Gated Recurrent Unit (GRU) based model has the best predictive ability.

Development of novel mixed matrix membranes (MMMs) for oil sands wastewater treatment: A critical review

AbstractWhile oil sands production plays a significant role in Canada's economy, the rise in oil sands production leads to increasing water withdrawal, consumption, storage and contamination that threaten the sustainability of water sources, biodiversity, ecosystem and public health. Effective treatment and reuse of oil sands process‐affected water (OSPW) can be a strategic solution for these issues. Membrane technology has emerged as a favourite choice for OSPW treatment with high removal and energy efficiency, small footprint and facile operation, installation and scale‐up. However, challenges also exist for membrane technologies related to fouling that causes a rapid decline in membrane performance. Mixed matrix membranes (MMMs) prepared by mixing superhydrophilic zwitterionic materials and inorganic nanoparticles into host membranes are anticipated as next‐generation membrane designs with significant potential for OSPW treatment by achieving multifunctionalities including fouling resistance, improved water permeability, selectivity and mechanical strength. Reproducibility and feasibility for large‐scale industrial applications remain important research questions for the production of MMMs for OSPW treatment. This study provides new insight on the performance, stability and durability of MMMs, outlooking to the commercialization prospect of MMMs. The research outcomes therefore can provide valuable knowledge for the design and development of high‐quality membranes with the required characteristics for OSPW treatment applications.

Technology, technology, technology: An integrated assessment of deep decarbonization pathways for the Canadian oil sands

As a party to the Paris Agreement, Canada has an ambitious climate target of net-zero emissions by 2050. The country also holds the world's third largest oil reserves in the Alberta oil sands. Given increasing emissions from the oil sands sector, achieving Canada's net-zero target requires significant oil sands decarbonization. If, while phasing out fossil fuels, there is still a demand for Canadian oil sands, then the decarbonization of the resource production process becomes crucial. In this study, we use an enhanced version of the Global Change Analysis Model (GCAM) with a detailed unconventional oil sector for Canada, including mining and in situ resources. We ask, what is the future of the oil sands sector in deeply decarbonized global and Canadian economies? We address this question under four mitigation scenarios with varying global net-zero GHG emissions constraints, three additional representative lower carbon extraction technologies available for the oil sands sector, as well as global direct air capture (DAC) deployment. We find that lower carbon technology deployment allows a 20%–44% increase in oil sands production by 2050 for scenarios with net-zero GHG emissions in 2100 or 2075. DAC helps maintain oil sands production in the most ambitious global decarbonization scenario (net-zero GHG by 2050), without which low international oil demand makes Canadian oil sands production uncompetitive. Canadian oil sands production thus depends highly on the availability of lower carbon extraction technologies and international oil demand, which to a certain extent relies on the availability and global deployment of negative emissions technologies.

A stochastic mixed integer linear programming framework for oil sands mine planning and waste management in the presence of grade uncertainty

ABSTRACT The primary purpose of oil sands mine planning and waste management is to provide ore from the mine pit to the processing plant while containing the tailings in an efficient manner in-pit. Incorporating waste management in the mine plan is essential to maximize the economic potential of the mineral reserve and minimize waste management costs. However, spatial variability such as grade uncertainty results in ore tonnage variations, which leads to fluctuations in the quantity of ore to be processed and waste to be managed. This paper investigates the application of a stochastic mixed integer linear programming (SMILP) on oil sands mine planning to integrate bitumen grade uncertainty and waste management. Sequential Gaussian simulation is employed to quantitatively model the spatial variability of bitumen grade in the oil sands deposit. Multiple simulated orebody models are used as inputs for the SMILP model to generate optimal mine plans in the presence of grade uncertainty. The results demonstrate that the SMILP schedule generates 14% and 17% improvements in net present value compared to the E-type and ordinary kriging schedules, respectively. These results indicate that the SMILP model is a robust tool for optimizing stochastic integrated oil sands production schedules and waste management.

Canadian Oil Sands Extraction and Upgrading: A Synthesis of the Data on Energy Consumption, CO2 Emissions, and Supply Costs

As Canadian crude bitumen production from oil sands has increased in recent decades, the nation’s oil and gas industry has become a significant contributor to national greenhouse gas emissions. Canada has developed carbon emission reduction targets to meet its Nationally Determined Contributions and Mid-Century Strategy goals. A detailed profile of energy consumption pathways in the oil sands industry is necessary to identify potential areas of improvement and to monitor progress toward meeting emissions reduction targets. Much of the existing literature for oil sands modeling provides input assumptions with different technological boundaries. For a set of oil sands extraction and upgrading technologies, this study first reviews the literature and then quantifies energy input requirements, CO2 emissions, and operating costs for a set of consistent technological boundaries and energy units. Summary results refer to requirements and costs at the production facility, excluding transportation and blending costs. An energy system diagram of oil sands production that matches these boundaries is provided, which can be used by integrated assessment models, oil sands companies, and government ministries to evaluate the present and future energy consumption and emissions pathways of the oil sands industry.

The No More Pipelines Act?

On 28 August 2019, both the Impact Assessment Act (IAA) and the Canadian Energy Regulator Act (CERA) came into force, and Canada’s environmental assessment process and its regulatory regime for major energy projects were fundamentally changed. With this new legislation in place, is it fair to say that no new pipelines will be approved in Canada? The answer is likely yes but not solely or even largely as a result of this legislation. Changes in global oil markets have led to significant reductions in forecast production from Alberta’s oil sands. This implies that, with no new pipelines permitted, and assuming those with permits in hand are built, the network will be sufficient to cover forecast oil export demand well into the 2030s. As such, there is a tautological answer to whether new pipelines will be approved in Canada: they likely will not be, unless market conditions change substantially, because new pipelines beyond those currently approved will not be needed. Tautologies notwithstanding, Canada’s new regulatory regime represents a significant departure from previous legislation. This article asks whether it is likely that a new pipeline project could achieve approval under the combined process implemented in the CERA and the IAA. The answer is complicated but likely turns on two issues already prevalent in Canada’s pipeline debates. The first issue facing any new pipeline review would be the ability to reconcile such development with Canada’s responsibilities to Indigenous peoples. The second is the collision between Canada’s climate change commitments, cumulative local environmental effects, and new oil sands production enabled by new pipelines. While approval has been — and will continue to be — a political decision, the analysis presented herein shows that the combined consideration of cumulative environmental effects, greenhouse gas emissions, and the link between pipelines and oil sands growth is likely to make it more difficult to approve a pipeline. This is because, when combined with recent changes to judicial review doctrine in Canada, the new regime will make it much more difficult for regulators and political decision-makers to justify such approvals.

Uncertainty-based mine planning framework for oil sands production scheduling and waste management

ABSTRACT In oil sands mining, the production schedule must be integrated simultaneously with in-pit and ex-pit dike construction scheduling. Any extra mined ore is stockpiled for a limited duration, and the topmost layer of the overburden is used for land reclamation. An uncertainty-based mathematical programming model is developed based on mixed integer linear goal programming for oil sands production scheduling and waste management. The model aims to maximize the net present value (NPV) while meeting all required production and technical constraints. The reclamation strategy for the stockpiled ore and the destination of dike materials is determined to minimize costs. The model uses kriged estimates with a variance penalty scheme to minimize the financial risk from grade uncertainty associated with the production schedule. The uncertainty-based model is implemented for an oil sands mine case study with two scenarios. An integrated mine plan with a waste management and stockpiling strategy is generated by Scenario 1 that maximizes the NPV of the operation and minimizes dike construction and reclamation cost. Scenario 2 uses the variance penalty scheme to estimate the production schedule financial risk from grade uncertainty.

Partial Least Squares Regression of Oil Sands Processing Variables within Discrete Event Simulation Digital Twin

Oil remains a major contributor to global primary energy supply and is, thus, fundamental to the continued functioning of modern society and related industries. Conventional oil and gas reserves are finite and are being depleted at a relatively rapid pace. With alternative fuels and technologies still unable to fill the gap, research and development of unconventional petroleum resources have accelerated markedly in the past 20 years. With some of the largest bitumen deposits in the world, Canada has an active oil mining and refining industry. Bitumen deposits, also called oil sands, are formed in complex geological environments and subject to a host of syn- and post-depositional processes. As a result, some ores are heterogeneous, at both individual reservoir and regional scales, which poses significant problems in terms of extractive processing. Moreover, with increased environmental awareness and enhanced governmental regulations and industry best practices, it is critical for oil sands producers to improve process efficiencies across the spectrum. Discrete event simulation (DES) is a computational paradigm to develop dynamic digital twins, including the interactions of critical variables and processes. In the case of mining systems, the digital twin includes aspects of geological uncertainty. The resulting simulations include alternate operational modes that are characterized by separate operational policies and tactics. The current DES framework has been customized to integrate predictive modelling data, generated via partial least squares (PLS) regression, in order to evaluate system-wide response to geological uncertainty. Sample computations that are based on data from Canada’s oil sands are presented, showing the framework to be a powerful tool to assess and attenuate operational risk factors in the extractive processing of bitumen deposits. Specifically, this work addresses blending control strategies prior to bitumen extraction and provides a pathway to incorporate geological variation into decision-making processes throughout the value chain.

Development of a framework for the assessment of the market penetration of novel in situ bitumen extraction technologies

Greenhouse gas (GHG) mitigation opportunities from emerging in situ mining technologies in oil sands production can play a role in reducing global warming. There is limited research on quantitative assessments of the penetration of emerging oil sands technology in the energy sector. This study addresses this gap by developing a novel framework (MAPL-OET) to assess the market penetration of emerging oil sands extraction technologies. The framework is robust and data-intensive as it combines diffusion models, econometrics models, cost models, and energy-economy equilibrium models. The combined model evaluates the adoption of new energy technologies resulting from carbon price measures and other economic factors, as well as the GHG mitigation potential in the oil sands sector. The accumulated GHG mitigation potential from high carbon and BAU scenarios (i.e., a carbon price of $30/tonne of CO2 in 2030, increasing at a rate of 4%/yr to reach about $105/tonne of CO2) was estimated to be 192.8 Mt of CO2 eq between 2018 and 2050. New extraction technologies also improve average energy intensities by 1.3% annually in the high carbon price scenarios. The developed new framework can help public and private organizations to achieve energy or environmental targets.

Temperature-Induced Transition from Indirect to Direct Adsorption of Polycyclic Aromatic Hydrocarbons on Quartz: A Combined Theoretical and Experimental Study

Adsorption of polycyclic aromatic hydrocarbons (PAHs) on mineral surfaces plays an important role in many engineering fields, such as oil recovery and oil sands production. In this work, the adsorp...

A crude future? COVID-19s challenges for oil demand, supply and prices

Assessing prospects for future oil prices is an uncertain activity but, barring Middle East conflict creating severe supply issues, crude oil prices are expected to stage a recovery by third-quarter 2020 and modest further recovery in first-half 2021, with the range $40 to $60 per barrel for WTI and Brent. Despite such a recovery there will be many oil sectors incurring losses, from US shale oil and Canadian tar sands producers, to many standard crude oil exporters incurring problems with production equipment access and costs, or experiencing lack of competitiveness in key markets.

An automated production targeting goal programming framework for oil sands mine planning considering organic rich solids

ABSTRACT In oil sands mining, bitumen and fines contents are used to predict ore processability. However, experimental results show that certain solid fractions known as Organic Rich Solids (ORS) negatively affect the overall bitumen recovery. A conceptual mine planning framework based on a goal programming model for oil sands production scheduling and waste management is presented. Bitumen recovery is additionally adjusted based on the ORS content. The model features automated production targeting (APT) and limited duration stockpiling constraints that optimize the annual production capacities. The model is implemented with two scenarios. Scenario 1 uses processing recovery calculated based on Alberta Energy Regulatory requirements while Scenario 2 uses processing recovery additionally adjusted based on ORS content. Results for Scenario 1 show a 3.46% overestimation of net present value compared to Scenario 2. The APT constraints provide planners a robust and efficient technique for determining annual production tonnages with minimum periodic variations.

An assessment of opportunities for cogenerating electricity to reduce greenhouse gas emissions in the oil sands

The purpose of this research is to evaluate greenhouse gas emission reduction opportunities from cogenerated electricity in oil sands production. A novel combined market penetration and bottom-up energy system modelling framework was developed to assess the long-range potential and marginal costs of cogenerated electricity in the oil sands. Feasible scenarios for incorporating cogeneration into the in situ, surface mining, and upgrading subsectors were developed along with four additional scenarios incorporating electricity-based technologies to improve in situ plant efficiencies. These scenarios were evaluated under three different carbon pricing policies; twenty-one scenarios in total covering the time period 2019 to 2050. The use of cogeneration in the oil sands for new production during this period was determined through market penetration modelling and the results were compared to a reference scenario of limited cogeneration growth. It was found that there is potential to provide 76 million tonnes of greenhouse gas abatement (2% of cumulative projected oil sands emissions) at a marginal cost of $15 per tonne of carbon abated compared to the reference scenario. The incorporation of electrical equipment, specifically well-pad boilers, well-pad compressors, additional steam compressors, and steam superheaters, resulted in additional costs that outweighed the benefits. A $50 per tonne of carbon dioxide equivalent carbon price (within the current Alberta emission reduction regulation) resulted in a 2% increase in forecasted greenhouse gas abatement potential and a $1.4/tonne of carbon dioxide equivalent decrease in marginal abatement costs compared to no carbon pricing. This research provides quantification of the greenhouse gas emission abatement potential and marginal abatement costs of cogeneration technologies to allow industry stakeholders and policymakers to compare these technology options to others when considering long-term greenhouse gas emission reduction.

Ambient concentrations and total deposition of inorganic sulfur, inorganic nitrogen and base cations in the Athabasca Oil Sands Region

Trace gas, particulate matter and deposition data collected in the Athabasca Oil Sands Region (AOSR) from 2000 to 2017 were evaluated as part of a broad scientific programmatic review. Results showed significant spatial patterns and temporal trends across the region. Concentrations of reactive gases were highest near the center of surface oil sands production operations and decreased towards the edges of the monitoring domain by factors of 8, 20, 4 and 3 for SO2, NO2, HNO3 and NH3, respectively. 18 of 30 sites showed statistically significant (p < 0.05) negative trends in SO2 concentrations suggesting an ~40% decrease since 2000. In contrast, only 2 of 30 sites showed statistically significant temporal trends (1 positive, 1 negative) for NO2. NH3 data showed (i) intermittent wildfire impacts, and (ii) high seasonality, with low concentrations during winter and significantly higher values during the summer. PM10 measurements were more limited, but also showed significant spatio-temporal variability. Comparison of PM10 and PM2.5 data showed that >80% of SO42− was in the PM2.5 fraction, while > 60% of Ca2+, Mg2+, Na+ and Cl− were in the PM10-2.5 fraction. Ion balances of both PM10 and PM2.5 contained cation excesses at near-field oil sand sites, but PM2.5 samples at forest health sites >20 km from surface production locations contained anion excesses. Monthly average concentrations of PM10 ions showed peak Ca2+ during March-April to November, but peak SO42−, NH4+ and NO3− from November-March. Deposition estimates showed rapid declines as a function of distance to oil sand operations. Estimated total N and total S deposition to forest health monitoring sites ranged from 2.0 to 5.7 kg ha−1 a−1 and 2.1–14.0 kg ha−1 a−1, respectively. Potential acid input (PAI) ranged from −0.46 to 0.79 keq ha−1 a−1 and was mostly 0.1–0.2 keq ha−1 a−1 throughout the domain, except for two clusters of sites near oil sand operations.