Pipelines are integral and essential infrastructure for the safe and efficient transport of oil and gas. Maintenance solutions employed to extend the longevity and safety of the pipeline network are vital in protecting the public and the environment. These solutions include programs such as dig sites, cathodic protection, class upgrades, hydrotesting, and above-ground features replacements (valves, launchers, receivers, etc.). Pre-planning for any of these programs requires individual site visits to each location and a thorough inspection to capture imagery and data about the site, access routes, crossings information, communications connectivity, proposed workspace, and terrain condition. Traditionally, each site visit involves deploying construction crews to access and assess the site, quickly becoming costly and time-consuming for operators. Since most of these sites are remotely located, this also requires driving long access routes by off-road vehicles, introducing additional safety hazards along the way. In this presentation, we present a new approach to limit the number of boots on the ground and add an enhanced interactive web-based visualization interface. The objective is to provide a safer and cost-saving alternative, as well as a sustainable solution that can be used in several other asset management applications. This approach includes integrating several sources of data based on the application and scope, such as Remotely Piloted Aircraft System (RPAS), terrestrial and sub-surface systems (laser scanning, mobile mapping, Ground Penetrating Radar and 360 cameras) and traditional surveying and line locating. This integrated data will be coupled with the site database and any relevant attributes and hosted on a GIS-based web-portal, providing up-to-date data that can be accessed and easily navigated from any location. Case studies, which include real-life examples and samples of virtual site visits, will be presented. This includes a recent site visit for one pipeline operator using UAV flights highlighting the access points to remote sites in different provinces, 360 panoramic images (aerial and ground) showing the terrain condition, and all pipeline and access crossings. The example virtual site visit reduced the number of field personal onsite from an average of eight to only two, significantly mitigating safety hazards through elimination. Cost-savings of around 60 per cent versus previous traditional site visits were observed. The developed web-portal provided an enhanced interactive visualization tool for planning, decision making and future maintenance and operational programs. In addition, the hosted data on the web-portal is considered the base for the client’s asset management programs.

ALBERTA H2 has developed a system that generates gaseous hydrogen and oxygen products employing much of the equipment that is typical of existing oil and gas facilities. It was designed to enhance and supplement the assets currently employed in Western Canada for oil and gas extraction and will be of primary interest to producers interested in reducing their carbon emission intensity (CI). The key component of our modular system is the Dynamic Hofmann Electrolyzer, which employs standard oilfield equipment, except that the materials of construction are both more robust and of a superior metallurgy (typically Duplex, PTFE). It employs a simple electrode design that actively protects against electrode degradation and system performance reduction. Side reactions are inhibited by careful pH control. The effect of sour components and hard water components have both been included for. In particular, there are provisions for the effective and quick removal of gas bubbles from the electrode surface. The device employs on-board, on-line cleaning to maintain electrode viability / conductivity. Electrode change-out (as required) can be done on-line. Turndown is 10:1 or more, depending upon the number of modules installed. At high voltage, electrode power density varies up to 50 Amp/dm2 (500 mA/cm2). Hydrogen generation efficiency can be 75% of Direct Current input, depending upon water quality and electrode cleanliness.

Natural rocks can be heterogeneous due to complex diagenetic processes that affect mineralogy and pore architecture. Correlation of geomechanical and transport properties of rocks in three dimensions can lead to large variances in data when tested experimentally. 3D-printed rock analogs made from sand is a promising alternative for experimental testing that can be used to calibrate different variables during geotechnical testing [6-9]. While 3D-printed sand is a homogeneous material, the parameters for creating grain packing, porosity and pore infill can be tuned to mimic specific geomechanical and transport properties. Initially, the 3D-printed specimens suffer from decreased density, uniform distribution of grains and lack of compressive strength. Herein, we detail our efforts at increasing the density through incorporating a roller in the printing process to compact individual layers. We also present how the density of rock analogs can be increased through incorporation of a more heterogeneous sand mixture that encompasses a wide range of grain size distributions, close to natural sandstones. Lastly, a relationship between binder saturation (that infills the pore space) of the 3D-printed specimens and the axial strength, dimensional control and porosity is described within. 3D printing of rock analogs is critical in pursuing rigorous destructive tests required for geotechnical and geological engineering because it can provide repeatable, controlled data on rock properties. The use of sand to create test samples for verification of experimental modelling is an unprecedented achievement that integrates geoscience and engineering. 3D-printed rock provides stakeholders with a tangible, physical specimen with repeatable properties for use in experimental studies.

Distributed fiber optic sensing has become a reliable method of preventative leak detection, ensuring pipeline integrity and delivering value added services such as pig detection/tracking and flow monitoring. A number of practical challenges such as the high risk and cost prohibitive nature of daylighting buried pipelines have resulted in the deployment of this technology being primarily limited to new pipeline projects. In this paper, we present internal deployment, among other potential retrofitting approaches, as a viable method of retrofitting existing pipelines, especially in high consequence areas. Hifi’s high fidelity distributed sensing system (HDS) is capable of sensing acoustics, temperature, strain, and vibration. We present a case study for the deployment of this sensor system inside and outside a gas pipeline in Canada. We will discuss the practical design considerations for deploying this technology inside a pipeline, including the use of tow pigs for pulling the fiber optic cable inside the pipe, proper design of a pig launcher, selection of appropriate pressure levels during fiber injection, and choosing a reliable dislodgement mechanism to separate the fiber optic cable from the tow pig. The paper will provide a comparison of the sensitivity levels of the internally and externally deployed fiber optic cables. Results from field verification and validation tests for the two sets of fiber optic sensors will be provided to showcase the effectiveness of internal deployment as a reliable pipeline monitoring solution. The field tests included tap tests, water and nitrogen based external leak simulations, and right-of-way ground disturbance testing. Some challenges with internal deployment will be reviewed as well, including deployment length limitations and the potential need to retract the fiber optic cable prior to pipeline pigging or closing any block valves. Possible solutions such as piggable internal deployments and automatically retractable lines will be discussed.

Objective/scope Demand uncertainty, increasing renewable competitiveness and growing climate change regulatory and policy frameworks are leading oil and gas companies towards an uptick in decarbonization ? and down the pathway to an energy transition. A necessary change, but a growing challenge to navigate as companies become increasingly strapped for cash. With capital markets putting a closer eye on ESG and non-financial performance ?" some even taking action to divest ?" oil and gas companies must act now to accelerate their ESG performance and demonstrate their long-term value to secure the capital needed to see this down cycle through and become fit for the future. Methods/process Black swan events faced by oil and gas companies this year have demonstrated that no strategy is immune to disruption. This presentation will explore the factors that will drive a slow, medium and rapid adoption of decarbonization, and the importance of scenario planning to account for even the most unthinkable events when establishing a energy transition strategy. Results/conclusion There are three conclusions that we hope the audience will take away: • The relevance of scenario planning to create long-term strategies that are validated and stress-tested for uncertain and complex environments based on slow, medium and rapid decarbonization adoption scenarios. • The role technology will play as a key enabler to both reduce emissions and support measurement for effective disclosures that will build trust and transparency in capital markets. • How to successfully position the company to attract sustainable finance initiatives to support investments in infrastructure and renewable energy sources. Actioning these items to implement and measure decarbonization will help companies secure greater capital and attract the next generation workforce that the industry will require to move forward. Additional info This presentation will pull from first-hand experience on developing the approaches, addressing the challenges and learning the best practices from some of the world’s leading oil and gas companies as they implement decarbonization. It will also look beyond the energy sector to explore successful methods from our work with clients across other industries that can be applied to oil and gas companies.

Canacol Energy has been investing in improving the reservoir characterization of its assets by the use of modelling and simulation techniques. Those techniques make use of regular surveillance data in a matter that allows geoscientist to understand the reservoir connectivity better to create accurate conceptual models that can be verified and fine-tuned with seismic data. One of the main improvements of this workflow is the integration of seismic attributes and surveillance pressure RFT, PLT, noise logs and production data to understand channel size, direction and connectivity between wells. Thanks to the integration of these data Canacol has effectively predicted sand connectivity, possible issues behind casing, and changes in estimates of OGIP. The use of RFT and noise logs data has proven to be specially effective in detecting vertical connectivity between sands that happens over time, increasing the volume of gas connected to the wells. This paper highlights the workflow used to characterize reservoirs using each piece of data, but understanding its limitations and uncertainties.

As an industry, we are striving towards the ability to be more predictive and proactive about our pipeline infrastructure’s construction, operations, and maintenance. One of the main ways that this will be possible is through artificial intelligence. However, lost in the push for ML/A.I. solutions is the substantial data preparation efforts required to build a foundation of trustworthy and accessible data suitable for use in A.I.-based solutions. Expert estimates indicate that over 80% of a digital transformation budget must be allocated to gathering, standardizing, and validating the data sources that will drive our A.I. solutions. It is imperative that owner/operators consider the key steps and data best practices that must occur, both on new projects and on their existing infrastructure, to achieve a trustworthy and accessible baseline of data that will feed predictive analytical solutions. Current state includes vast arrays of data trapped in unusable formats, such as PDFs, along with data that has not been validated for traceability, accuracy, and conformance to specifications. Organizations must investigate their existing data and records, evolve how they purchase new material, and consider their data sources stemming from construction, operations, and maintenance. This change management will be critical for the industry as we move towards more digital operations. Presentation supported by two case studies (historical and new construction) and a use case of two 3D models illustrating what was engineered versus what was fabricated and installed showcasing how ML and AI are susceptible to the garbage in, garbage out scenario.

Blue Hydrogen Co-production from GTL Plant Authors (*): Jan Wagner, P.Eng. Wagner Energy Consulting Inc. Steve Kresnyak, P.Eng. Expander Engineering Services Inc. (*) Co-presenters as well Background World will move eventually towards decarbonization of energy sources and zero carbon hydrogen will be increasingly in demand. The ultimate hydrogen society will be based on green hydrogen. As green hydrogen is currently the least economic option, blue hydrogen could be the interim solution. Blue hydrogen is derived from natural gas and must include carbon utilization or sequestration. The immediate solution can be to co-produce hydrogen with synthetic clean fuel production, such as gas-to-liquids (GTL) plants, whereby the process carbon from the natural gas is captured and utilized in the synthetic fuel. Study Basis The traditional way to produce hydrogen is Steam Methane Reformer (SMR) technology with about 90% of world hydrogen being produced this way using natural gas as feedstock. The SMR process economically produces raw syngas with H2/CO ratios of 3.0 to 5.0 and the carbon is subsequently converted to CO2 and released to the atmosphere. The issue here is the disposal or utilization of CO2 if hydrogen is the only final product. The only solution is to install carbon capture and sequestration to achieve Blue Hydrogen and avoid CO2 emissions. Beside hydrogen production, syngas can be utilized for several downstream processes such as methanol or GTL. SMR inherently produces syngas with above stoichiometric H2/CO ratios. Excess hydrogen is therefore available and can be removed as valuable co-product and the carbon in the syngas can be fully consumed in the downstream synthesis. Significant CO2 emissions can be avoided. To verify the feasibility of this concept an existing small capacity GTL plant was used for a case study. Case Study Results The study was based on hydrogen co-production from an existing GTL plant with capacity 500 bpd employing SMR for syngas generation. Membrane is used for excess hydrogen removal from syngas. The plant operates typically at steam/carbon (S/C) ratio of about 2.0 to 2.8. and any excess hydrogen in the syngas is removed and recycled back to the SMR as fuel. Increasing the S/C ratio, the plant will produce more hydrogen, but the following variables will be impacted: total feed and fuel gas, SMR duty and to lesser extent CO2 emissions. A parametric study with varying S/C ratio was conducted to identify the impact on the above values. The study for the 500 bpd GTL plant over varying the S/C ratios, indicates favorable economic results and further verified significant improvement in overall GTL plant carbon intensity due to the credit from downstream use of carbon free hydrogen fuel.

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 British Columbia. The prediction accuracy of the various combinations was measured by using the mean average percent error (MAPE) 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.

Oil & Gas companies face mounting pressure from all sides to achieve net-zero greenhouse gas emissions. Standards put forth by the Greenhouse Gas Protocol (GHGP) divide the emissions into three scopes: Scope 1, 2, and 3. Although this decarbonization is a serious challenge, it does not have to be as costly as you may think. In fact, there are practical steps that can be taken with the electrical system that will realize reduced Scope 1 and Scope 2 greenhouse gas emission reductions while at the same time offer sizeable returns on investment to the operator.
Electric motors are the workhorses in a pipeline and processing facility. These electric machines account for up to 70% of the electrical loads. Applying medium voltage (MV) adjustable speed drives (ASDs) for flow control and energy savings have been well understood and documented for decades. This savings in turn reduces the electric demand and therefor the carbon footprint associated with the generation of that demand. Another less understood method of reducing greenhouse gas emission is using ASDs for power factor improvement. By improving power factor the operating will see a corresponding electric bill savings and reduce even further the carbon footprint associated with power generation. While ASD has historically been used to impact the bill's energy component, it's only recently that ASDs gained capabilities to influence the power factor. This is a powerful capability that makes a case for applying drives very compelling.
In this presentation, we give an overview of the Greenhouse Gas Protocols and practical solutions that can bring progress towards these goals using available technology. The presenter will provide a deeper understanding of the monetized value by a novel approach to applying an ASD that reduces your Scope 1 GHG while saving you significant electrical consumption and costs.

Alberta is endowed with an oil and bitumen resource of 1.6 trillion barrels in place. Current in-situ (subsurface) extraction limits the recovery factor to no more than 40%. In Alberta, roughly 15 billion STB of medium to heavy oil (excluding bitumen and tar sands) are found within 1000 m of surface. It is recognized that there are substantial releases of CO2 by utilizing this energy source. Trindade Reservoir Services has developed and patented a process that utilizes a reconfiguration of existing petroleum and geothermal technology to generate temperatures well over 1000 degrees F in the reservoir and exploit this thermal resource. This enormous amount of heat can be harvested by the careful layout of wells and well types and process controls. This offers significant advantages over different geothermal methods of heat recovery. These include minimal geologic exploration risk, very low drilling costs and higher efficiency of enthalpy extraction per barrel of water circulated through the reservoir. In addition, hydrogen and ethane generation (subsurface and surface) can also be generated, both subsurface and on surface using excess electricity capacity, which can be sold to market. The process is energy sufficient and all CO2 and other undesirable byproducts can be captured and stored in a deep geologic zone or sold for use in CO2 based EOR processes. The process reduces reliance upon oil pipeline export capacity and does not rely upon a significant source of water, and is scalable as the process matures and results of the reservoir response become clear. The process has flexibility to produce electricity, hydrogen or upgraded oil, allowing for the optimization of profitability as commodity prices change. The process has been validated by numerical simulation and economic evaluation.

Heavy-duty transportation is one of the best early applications for hydrogen and fuel cell technologies. To transition towards net-zero carbon neutrality by 2050, Canadian cities must adopt fuel cell electric buses and trucks in their urban fleets. For transit agencies and trucking operators, hydrogen powered buses and trucks are a proven zero-emission solution that offer excellent performance in terms of longer routes, colder weather, higher power requirements. In this session panelists will discuss the advantages of zero-emission hydrogen and fuel cell solutions for heavy-duty transportation, fueling infrastructure, and what is needed to overcome barriers to adoption.

Although there is an effort to implement the best project management practices worldwide, energy projects, regardless of size, complexity, or industry, still experience difficulties meeting the three successful criteria. These criteria are: delivered on time, with a final actual cost on or below budget, and in full compliance with the technical and regulatory requirements. Energy projects are capital intensive, risky, and complicated endeavor. The larger the energy project, the greater the percentage of cost overrun and schedule slippage. It is imperative to reverse this trend to maintain a competitive edge in the energy sector. Two of the primary reasons why energy projects still experience difficulties to be successful are as follows. Firstly, the planning and construction phases are performed in a non-integrated way, where information is segregated into multiple systems, adding complexity to the challenging project environment. Secondly, the current practice to determine the project status during construction, using the activity percent complete technique, is an indirect and subjective method to determine progress. During the construction phase, project and construction managers are left tracking thousands of activities and tasks from multiple different contractors, and lose sight of the bigger picture. With an integrated approach, the planning phase's modeling starts with defining the scope of work ? with a results-based work breakdown structure, a work plan schedule, and a cost estimate based on project results defined as deliverables and work packages. During the construction phase, project performance is measured using earned value and earned schedule. Earned value is credited as deliverables and work packages are completed using the binary theory. This theory is a simplified approach to credit value only for the physical work completed, increasing objectivity to determine the project percent complete and forecast final cost and completion date when closing each measurement reporting period during construction. Combining this result-oriented concept with a simplified application of earned value and earned schedule facilitates the planning and construction phases. It also increases the probability of success because projects are handled more objectively and proactively, based on performance. Besides, the integration with the financial system (invoicing) allows for tracking profit margins by deliverables. This methodology also enables monitoring programs and portfolios more effectively due to the consistency in recording productivity and efficiency indices (CPI and SPI, respectively), project percent complete, and forecasts of final cost and completion date. This integrated planning and construction methodology was developed to encourage private companies and government organizations to introduce changes in the way construction projects are handled nowadays to track margins, improve performance, and increase profits. The main challenge is to overcome current common practices during the planning and construction phases of energy projects.

Refineries and long-haul transport fuel users seek to adopt low carbon solutions to cover fuel demand while complying with the GHG reduction targets for 2030. However, there is a gap between renewable fuel producers, technology developers and refineries due to a lack of long-term reliable data to di-risk the incorporation of renewable molecules as feedstocks for upgrading at existing refineries. Furthermore, understanding storage and process requirements for co-processing and stand-alone upgrading of biocrude oils are crucial to facilitate the adoption of these feedstocks and define their market pathways. Steeper Energy is working towards bridging this gap by enabling existing refinery infrastructure to incorporate Hydrofaction® products as co-processing feedstocks. Advancements on biocrude stability, blending, and compatibility with petroleum feedstocks and identifying suitable pathways for co-processing have been carried out at Steeper’s Advanced Biofuels Centre in collaboration with catalysts manufactures and refineries. Hydrofaction® Oil is energy-dense, with a high heating value (HHV) of 38 MJ/kg, has low oxygen (~10 wt.%) and water content compared to other biocrudes and is rich in diesel boiling point range hydrocarbons. Although Hydrofaction® Oil resembles its fossil counterparts, its distinct properties need to be considered for upgrading, i.e., viscosity, total acid number (TAN) and oxygen content. Raw Hydrofaction® Oil may be used as a multi-purpose heavy fuel oil for large reciprocating engines such as those used in marine propulsion and power generation. Due to its oxygen content, Hydrofaction® Oil has physical and chemical properties that differ from petroleum which affect its blend-ability. Extent of blending is dependant on the polarity and heteroatom content of the blending feedstocks. Therefore, upgrading of the Hydrofaction® Oil is required to reduce the heteroatom content, viscosity, and density, as well as increase its HHV and H/C ratio, to enable complete compatibility with petroleum feedstocks. Partial upgrading results in improved blending, and in some cases full blend-ability with petroleum derived Vacuum Gas Oil (VGO). This upgrading stage decreases the biocrude’s oxygen content, TAN, viscosity, density, and micro-carbon residue, and improves its thermal stability while shifting its boiling point distribution towards lighter hydrocarbons. Optimal blends that were hydrotreated at industrially relevant conditions did not considerably affect the desulfurization yield compare to VGO baseline. The biogenic distribution for various process schemes was determined; results have shown the maximization of biogenic content in liquid fractions.

Due to current economic and operational challenges, HSI’s clients approached us to design a remote monitoring system. There were a number of challenges present for site operation, including access, geographical limitations, staffing constraints, limited time on each location, environmental risks, and safety concerns. We devised a solution that could provide automated 24/7 site information via high speed wireless data utilizing integrated cameras and new AI features. We collaborated with technology manufacturers as well as Calgary-based energy producers. The goal was to incorporate their viewpoint as the on-site well operators. With their support and our design we created our new consumer-level industrial technologies product with no monthly operational costs or upkeep requirements. We have a selection of cameras offering a wide range of options for each application. This includes Pan-Tilt-Zoom for cameras that require movement, as well as fixed cameras for watching a specific location or device, thermal imaging for seeing potential HSE concerns or alerting operations changes, and explosion proof cameras for views within hazardous locations or even vessels. Our team was also mindful or the requirement for multiple voltages: 12vdv, 24vdv, 120vac, and solar/TEG offerings. We approached our first product from the viewpoint of our customers’ needs ? which meant tailoring the solution towards monitoring remote wellheads and locations. Then we built on that success by creating large wireless point to point networks to allow customers to add more devices. These networks started with simple connections (under 400 meters) and moved up to a couple kilometers. We then reached multi-points from multiple towers and connections tied into large scale multi-kilometer network assemblies. With our data back bones in place and our customers positively responding to the idea of owning their own equipment with no monthly costs, we put our sights on creating more innovations for our applications. In the end we created a design for sites that utilize a wireless backbone and a camera with installation for approximately $1,000 per location. With the support of our technology partner, Hikvision, we have implemented applications for ColorVu night vision. This technology allows for ultra high-definition views with full color in the darkest of conditions on remote wells without the requirement of additional lighting or infrastructure. We streamlined the IT operation with the integration of Hik-Central and the use of Microsoft active directory - allowing a simple way of connecting to the applications and maintaining user databases. Driven by the demands at the field level, our next offering was to allow monitoring of sound from site and to provide the ability to speak to people on locations. The sound-from-site was a request from a user with older wells who had a risk of pump jacks being off balanced and making noise or having a gas leak on the wellhead. Our next request was a bi-spectrum thermal imager on site with dual lens - thermal and HD video - for less than $1,500. Once again, with the support of Hikvision we attained this and now have them implemented on locations with for leak detection, packing failures, SAGD wellhead and flowline issues, pipeline and header monitoring. We are proud to offer a dedicated view on location solution with integrated AI to support your production, midstream, and refining processes

Hydrogen is an alternative to fossil fuel with many benefits. It produces zero carbon emissions in use, is critical to decarbonizing industrial processes. However, while hydrogen is a potential product of the MSW gasification process, it is not currently a priority. This research explores the feasibility of adjusting the gasification of MSW to maximize hydrogen production through a technoeconomic analysis.

Canada’s estimated total municipal waste generation is about 25 million tonnes per year, 15% of which is from Alberta. This translates to a Canadian average of 720 kg of waste per person and an Alberta average of 1,000 kg of waste per person, the highest in the country. Gasification is one of the most promising thermochemical recycling techniques for extraction of the untapped energy that make up plastics and other biomass waste in MSW. Syngas consists of a mixture of Hydrogen (H2) and carbon monoxide (CO), which can be converted to electricity, renewable diesel, ethanol, hydrogen, fertilizer and other renewable chemicals. As MSW is considered a negative value waste stream, MSW gasification produced hydrogen, coupled with carbon sequestration, has the potential to economically produce hydrogen with zero or negative greenhouse gas (GHG) emissions.

Existing research has shown that the addition of some plastics at certain ratios to biomass waste can enhance the hydrogen production concentration in the syngas. Gasifying waste streams is also often constrained by contaminants in the feedstocks since they are known to bind with and disable the catalysts needed to drive the gasification process to the production of desirable end products like hydrogen. These results are used to evaluate the optimum composition of feedstock for gasification of MSW (plastic, wood and cardboard waste) in Alberta.

The economic feasibility of this process is also analyzed in light of the gradual increase of carbon tax to $170/ton of CO2 by 2030. In addition, the feasibility of the addition of a carbon capture, utilization and storage (CCUS) facility to such plants is analyzed from an environmental and economic standpoint. Through this research’s conclusions pathways to additional plastic and biomass waste gasification deployment for hydrogen production combined with CCUS in Alberta is highlighted and the conditions under which the process can be economically feasible will be discussed. This in turn will lead to further reductions in Canada’s GHG emissions, support the drive to carbon net zero and support the Canada Wide Strategy on Zero Plastic Waste.

Coauthors: Dr. Daya Nhuchhen, PhD, Peng, Energy Systems Analyst, Canadian Energy Systems Analysis Research (CESAR) Initiative, University of Calgary
Dr. David B. Layzell FRSC, Energy Systems Architect, The Transition Accelerator, Professor and Director, Canadian Energy Systems Analysis Research (CESAR) Initiative, University of Calgary; Dr. Josephine Hill, Professor, Department of Chemical and Petroleum Engineering, University of Calgary

Once Through Steam Generators (OTSGs) recycle steam-assisted gravity drainage (SAGD) produced waters for steam production to improve energy efficiency and lower the environmental footprint of the SAGD operations. Additionally, the increased water recycle rates helps conservation of water. SAGD produced waters contain considerable amounts of dissolved constituents including calcium, magnesium, iron, sodium, silica, organics and suspended matter during bitumen recovery which are treated to meet boiler feed water (BFW) quality. Despite treatment some of these BFW constituents are prone to cause mineral (scale) and organic precipitates (fouling) upon heating during steam-generation, resulting in higher tube wall temperatures, which can cause premature OTSG failure. A state-of-the-art pilot OTSG pilot skid was built in collaboration with ConocoPhillips to investigate the chemical and process changes to reduce the inorganic and organic tube fouling occurrences in OTSGs, while improving the efficiency of steam generation. The objective of this study was to systematically investigate the efficacy of four chemical additives against tube scaling/fouling with synthetic and SAGD boiler feed water chemistries under high pressure and temperature operating conditions. The relative performance of four chemical additives was evaluated against synthetic and actual SAGD boiler feed water chemistries under operating conditions of ~314°C temperatures and ~11 MPa pressure. The additives include: ‘Additive A’: a boiler polymer; ‘Additive B’: a boiler polymer with silica inhibitor; ‘Additive C’: a silica inhibitor; and ‘Additive D’: an organic dispersant. Within the first phase of experiments, the baseline skin temperature profiles for the synthetic and SAGD boiler feed water chemistries were established. Each additive was then applied to identify any changes in the performance of the OTSG pilot skid. A combination of process conditions, chemistries, surface temperature profiles and ion balance analyses were used to evaluate the comparative efficiency of each additive and identify any changes in behavior and performance. ‘Additive A’, boiler polymer, showed a decrease in the skin temperature relative to the baseline indicating it’s effective in reducing the extent of scaling/fouling occurring within the skid. While being effective in reducing scaling/fouling extent, the ion balance studies showed the ‘Additive A’ resulted in significant precipitation of magnesium silicates within the pilot skid. ‘Additive B’, boiler polymer with silica inhibitor, showed similar results as ‘Additive A’, with reduced precipitation magnesium silicate salts. Upon comparison of skin temperature profiles, the ‘Additive D’, organic dispersant, showed the best performance amongst the additives, with a significant decrease in the skin temperature relative to the baseline. Overall, the results obtained from this study will be used to help industry enhance the understanding of potential problems and solutions associated with dissolved organics and inorganics in OTSG boiler equipment fouling and scaling with additives that may accelerate water recycle rates and reduce the environmental footprint.

Expander Energy is a Calgary based Energy Technology firm that has developed a patented suite of transportation fuel production technologies based on the Fischer-Tropsch conversion method using Biomass, Natural Gas and Bitumen residue as feedstock for the process. Fischer Tropsch Gas to Liquids Expander (through its affiliate company Rocky Mountain GTL) will start-up its first Natural Gas to Liquids (EGTL™) facility in Carseland Alberta in Q2 2021. The Facility will produce 500 BPD (28 million liters/year) of Synthetic Paraffinic Diesel and Naphtha as well as 16 tonnes/day of surplus Hydrogen. Biomass / Gas to Liquids Expander in partnership with the Vanderwell Sawmill, are in the final stages of developing a Biomass to Diesel Facility in Slave Lake Alberta. The Slave Lake facility will be a commercial demonstration of Expanders Biomass / Gas to Liquids (BGTL™) technology. We expect that the plant will be operational in Q3 of 2022. The facility will utilize 22.4 t/day of forestry waste plus 1.5 mmscfd of natural gas to produce 120 BPD (6.1 million liters/year) of low carbon Synthetic Paraffinic Diesel (SPD) and / or FT Synthetic Paraffinic Kerosene jet fuel (FT-SPK) and Naphtha. Expanders BGTL facility when running at full production will produce 45 BPD of renewable paraffinic diesel (SPD) with Carbon Intensity of 3.7 gCO2/MJ and 70 BPD of natural gas derived Synthetic Paraffinic Diesel (SPD). with a blended carbon intensity of 56.8 gCO2e/MJ (43% less than the BC LCFS default of 98.96 CI) The facility will also produce 2.7 tonnes / day of surplus low carbon intensity “blue” hydrogen for transportation, industrial and residential use. Front End Engineering for the Slave Lake Biomass to Diesel facility is complete and we expect to have Governmental regulatory approvals in hand by Mid January 2021. Expander expects to have project financing finalized and make a final investment decision in late January 2021 In Slave Lake, the gasifier will utilize forestry residual hog material as feedstock. Expander plans to test the gasifier using osb cut-offs, agricultural by-products, landfill redirect, municipal sludge and railway ties. We expect that on completion of our commercial demonstration the Slave lake facility will be immediately expanded, and several other prospect locations will be developed. On successful commercial demonstration in Slave Lake, further development will proceed on Expanders next generation Biomass / Electrolysis to Liquids (BETL™) technology. Electrolysis of water is utilized in lieu of natural gas to balance the H:CO ratio for FT conversion. This technology will result in zero Carbon Intensity (CI) fuel production when using low CI / Hydro electricity in jurisdictions like BC, Manitoba, Quebec and Labrador. Expanders suite of technologies will utilize plentiful Canadian natural gas and non-food related biomass to create a sustainable domestic supply of low CI Synthetic Diesel / Jet fuel and reduce the Carbon Intensity of the Canadian transportation energy mix.

In Alberta, Canada steam assisted recovery processes, such as SAGD and CSS processes are commercially used for bitumen and heavy oil production. Recently, oil industry invested in development of solvent co-injection with steam processes to improve bitumen recovery by reducing bitumen viscosity, which resulted limited commercial success. At our laboratory reduction of bitumen-water interfacial tension using surfactants was studied to improve bitumen recover efficiency by reducing bitumen-water interfacial tension. For this purpose, we studied in-situ sulfonation-sulfoxidation of bitumen asphaltenes to surfactant species by injecting a trace amount of gaseous SO2 with steam and co-injection of biodiesel (BD) as a surfactant additive with steam. BD is the commercial name of fatty acids methyl esters (CnHm-COO-CH3; m<2n+1), which behave as molecular surfactants by possessing hydrophobic (CnHm) and hydrophilic (COO-CH3) functional groups. BD are immiscible with water, boil at 325-400 oC temperatures at atmospheric pressure, possess sufficiently high vapor pressure, where saturated BD concentrations in steam are high enough to perform as surfactant additive under SAGD and CSS operating conditions. Laboratory scale bitumen recovery tests supported with interfacial tension measurements on BD-bitumen-pentane-water systems show that, BD is a suitable surfactant additive at about 2 g-BD/kg-bitumen dosages (corresponds to 0.670-kg/ton-steam if W/B ratio is 3:1) to improve bitumen recovery efficiency by about 40%. Interestingly, our tests simulating solvent co-injection with steam operating conditions resulted in lower bitumen recovery efficiency, which could indicate the importance of bitumen-water interfacial tension on bitumen mobility, therefore, recovery efficiency. We are expanding our research on use of BD as surfactant additives for UOR process. For this purpose, BD-water emulsions flooding, potentially with polymer addition also, are being studied for cold heavy oil, CHOPS, Post CHOPS and tertiary oil recovery applications. BD-solvent (light hydrocarbons)-water flooding will be studied for extra viscous heavy oil recover, and bitumen recovery from high permeability reservoirs. The present paper will present data generated on solvent versus surfactant co-injections with steam for bitumen recovery, and mathematical models on the effect of slip velocity at bitumen-water interface on oil recovery efficiency. Key Words: Biodiesel as surfactant additive for SAGD and CSS processes, oil-water interfacial tension and oil mobility, biodiesel-water and biodiesel-solvent-water emulsions flooding.

Nelson Environmental Remediation (NER) has been offering Low Temperature Thermal Desorption soil remediation services for over 20yrs. The most commonly used method to treat hydrocarbon impacted soil is disposal at a landfill site. This method, however does not remediation the soil, it merely re-locates the problem while the property owner maintains the liability and is not sustainable in the long term. Low Temperature Thermal Desorption (LTTD) is an innovative process of remediating hydrocarbon contaminated soils, sediments and sludge in a sustainable manner which preserves the remediated soil for re-use that eliminates liability. LTTD is an Ex-Situ means of physically separating volatile and semi volatile organic contaminants from the soils through application of heat, incorporating sound environmental practices. Hydrocarbon impacted soils are placed in a chamber, and heated to volatilize the hydrocarbons. The contaminated gaseous vapors are then run through a bag house to remove particulates and the contaminants destroyed using a thermal oxidizer., converting them into carbon dioxide and water. The clean soil can be used to fill in the excavation at the site.

There are few historical precedents for the disruption that the oil sands industry experienced in the second quarter of 2020, and the market turmoil caused by COVID-19 naturally raised questions about the possibility of extended shutdowns and asset integrity issues. This presentation aims to provide a comprehensive review of Western Canada’s heavy oil sector against the backdrop of COVID-19 and its aftermath. In terms of historical trends, the analysis will focus on how upstream players responded to COVID-related demand destruction from an operational perspective. Forward-looking analysis will assess prospects for future oil sands growth and the evolving development concepts that will allow heavy oil players to grow at a competitive cost of supply. The presentation will conclude with a review of recent midstream developments. The analysis will utilize well-level data from provincial regulators and proprietary oil and gas databases from Rystad Energy, which provide global supply forecasts through asset-level production and economic modeling. The analysis of operational responses will disaggregate monthly heavy oil production trends by oil sands projects to assess varying producer responses to the extreme low-price environment witnessed in the second quarter of 2020. Meanwhile, presentation will utilize a bottom-up, asset-by-asset modeling approach to highlight the most prominent near- and mid-term oil sands expansion opportunities. Early fears surrounding complete shutdowns and thermal asset integrity ultimately did not come to fruition. Although many thermal operators reduced production dramatically in 2Q20, almost none of these curtailments involved extended disruptions to producing wells or the minimal production levels that some operators had initially guided. In fact, operator responses varied widely amongst both mining and thermal schemes. In some cases, the impact to production was minimal; in other cases, operators used the market disruption to schedule extended maintenance and ramp up production in 4Q20. Looking forward, oil sands players continue to shift away from greenfield projects and large-scale expansion phases towards a growth model characterized by smaller incremental expansions with reduced facility requirements. As such, oil sands projects will maintain a competitive cost of supply and continue to grow throughout the 2020s, albeit at a more measured pace. The well- and asset-level granularity that underlies the analysis in this presentation will be a valuable addition to the state of knowledge in the energy industry. In addition to purely historical trends, the review of historical data will offer insights into how oil sands players could reasonably be expected to adjust upstream operations in the face of future market disruptions. Additionally, our analysis of project economics and development strategies will provide industry stakeholders with a concise, yet empirically robust overview of the sources of future supply growth in the oil sands and their expected go-forward breakeven prices.

Objectives/Scope We present an extended local solution for upscaling based on 3D electrical circuits representing variable size grid blocks. Homogeneous parts of models are represented by fewer larger grid blocks while heterogeneous parts are represented by many smaller homogeneous grid blocks. An adaptive octree data structure is implemented in building and simulating models that are equivalent to 109 blocks. Simulations run on a typical laptop in minutes not hours and compare results from nine different upscaling configurations. This solution works well at pore scale and reservoir scale without modeling flow dynamics that limits the model size. Methods, Procedures, Process The upscaling is based on connectivity between two opposite faces of the model and follows principles of capillary pressure tests. In virtual tests at pore scale, the wetting and non-wetting fluids interact under varying pressure in a 3D effective network. This process simulates trapping mechanisms when one of the fluids is surrounded by a different fluid type. The model's electrical properties are derived from grid blocks at the lowest tree level through recursive upscaling in a depth-first traversal. The resistivity estimates come from statistical averaging and three different configurations for electrical circuits representing grid blocks. Our first two non-statistical models correspond to the earliest methods of the porous media simulations and upscaling based on bundles of pipes representing grid blocks. In the third method, blocks are replaced by sets of six resistors organized as 3D crosses. Sets of eight blocks with the same parent are replaced by 48-element circuits used to estimate the resistance in horizontal and vertical directions. This process models 3D effective network connectivity, checks fluid types, and tests path length versus pressure values. This extends simulations with a regular cubic lattice yielding a network coordination number greater than six. Results, Observations, Conclusions Prior to 100% saturation of the pore space with the wetting phase, the total porosity, the effective porosity, and the path statistics (tortuosity) are estimated. During the drainage-imbibition tests the non-wetting and wetting phase percentages are recorded along pressure values. These are accompanied with nine resistivity estimates. The first three estimates represent arithmetic, geometric, and harmonic averages. The remaining six estimates represent the resistivity estimates from the chain, bundle, and mesh algorithms in horizontal and vertical directions Different model structures result in varying degrees of the hysteresis in fluid saturations and electric properties during these tests. The most advanced mesh interconnectivity works best for layered and/or correlated pore networks. Break-through events are detected in drainage and imbibition. Saturations and interconnected paths at each pressure are visualized in 2D and 3D space. Novel/Additive Information The above procedures and algorithms model and estimate properties directly in 3D space. They are fast and do not require intermediate representations relaying on networks or packs of simple objects (e.g. spheres). Differences between nine estimates indicate uncertainties in upscaled properties prior to reservoir simulations. Finally, permeability estimates can be made by substituting permeability for electrical conductivity or by using known relationships between permeability and conductivity for specific rock types.

There is a growing interest in the use of novel technologies for monitoring methane emissions. These technologies have come to include handheld instruments, continuous sensors, vehicles, drones, aircraft, and even satellites. Dozens of new companies have emerged over the past decade offering a diversity of products and services. Available solutions differ significantly in performance, cost, data characteristics, interpretability, and capacity to recommend emission reduction activities. What technologies to use and where/when to deploy them will depend on a producer’s emission reduction goals, where their assets are located, historical emissions data, production characteristics, regulatory requirements, and so on. In other words, achieving methane reductions in the most cost-effective manner requires careful selection of the technologies best suited to a particular set of goals and constraints. A new, open-source software tool called the Leak Detection and Repair Simulator (LDAR-Sim) is able to evaluate different technologies and LDAR programs.1 LDAR-Sim is an agent-based numerical model and publicly available software tool designed for the oil and gas industry to optimize technology deployment and reduce methane emissions cost-effectively. To achieve the objective of empowering oil and gas companies to independently evaluate and confidently deploy novel methane monitoring technologies, we present a set of case studies on the use of LDAR-Sim. Our case studies explore a variety of scenarios to demonstrate the strengths and weaknesses of different technologies and show when and where their use makes sense. We perform thousands of simulations to explore where and when different technologies excel. Conditions explored include emissions profiles of different production types, regulations, environmental conditions, availability of infrastructure (e.g., roads, airports), facility densities, and best management practices for leak repairs and investigation of emissions sources. Our results demonstrate a broad range of emissions reduction potentials and highly variable LDAR program costs, showing that each of the aforementioned input variables are important to consider when determining which technologies to deploy. Based on our case studies, we conclude that technologies should be evaluated through simulation each time a new monitoring strategy is developed. Given the pace of change in innovation, emissions profiles, and emission reduction efforts in the oil and gas industry, iteratively revisiting reduction strategies and technologies used is important to remain competitive. 1 Fox, T., Gao, M., Barchyn, T., Jamin, Y. & Hugenholtz, C. An agent-based model for estimating emissions reduction equivalence among leak detection and repair programs. 2020. J. Clean. Prod. (In press).

Liquefied natural gas (LNG) has been around for decades and the usage is expanding globally. There are many large-scale LNG plants (> 1 mtpa) that are currently in design development phases through to operating plants. These large-scale LNG plants are located by the water near a port. The LNG is typically transported to other countries by LNG tankers or ships, then regasified and the natural gas is then transported via pipeline or truck to inland users. A new concept that has been developing over the last ten years is the use of small-scale (< 500 ktpa) LNG plants. Small scale LNG plants are typically located inland where natural gas is available from biogas, “stranded” unconventional and conventional gas resources or a natural gas pipeline. The LNG has been trucked for use by power generators and more recently been used in the heavy transportation markets including trucking, mining haul trucks, marine and rail. These small and micro scale standardized modular plants can be built faster and more efficiently than large-scale LNG plants. The competitive advantage of these small plants when compared to the large-scale plants are the smaller local gas resources are monetized taking advantage of the reduced logistics cost of transport liquid LNG over large distances to these end users. There are different liquification technologies that have been used for small-scale LNG plants and include methane expansion, nitrogen (N2) refrigeration and single mixed refrigerant (SMR). PolaireTech has developed a standard modular small (60 ktpa) and micro (5 ktpa) scale LNG plants utilizing the zero refrigerant (methane expansion) ZR-LNGTM technology. Utilizing the ZR-LNGTM technology reduces the overall lifecycle costs when compared to traditional technologies by minimizing the quantity of equipment and the power consumption required. The plant consists of standard plug and play modules that can be interchanged depending on the FEED sources and these plants are scalable depending on the customers’ requirements. Small and micro scale plants are becoming more popular globally due to the initiatives to reduce greenhouse gases, as LNG burns more cleanly than other fossil fuels such as petroleum and coal (reducing CO2 emission between 30 ? 50%) . There needs to be innovative cost-effective methods to construct these environmentally friendly plants and ensure the customer has a profitable “total cost of ownership”. This presentation will review the overall ZR-LNGTM technology, PolaireTech plug and play module methodology and the benefits of utilizing a zero-refrigerant technology versus the traditional N2 and SMR technologies. It will also discuss combining this technology with using biogas as a renewable energy source. It will highlight how the overall lifecycle costs play an important role in ensuring the customers “total cost of ownership” is met.

In addition to the low-carbon energy transition, companies are also radically transitioning their business process to be increasingly data-driven.

On the oil and gas side, profitability is being driven through efficiencies instead of additional exploration. While in renewables, big data, predictive analytics and machine learning may be the solution to improved forecasting.

What are the opportunities for implementing data solutions and how do they balance against, what can be, deep-seated data challenges?

Audience Insights:

This session provides examples from companies who have leveraged data to dramatically improve the way their business operates.

Technology: Chemical and mechanical processes uniquely combined to accelerate; and efficiently separate water, oil and tailings’ solids, aiding in the reclamation of oil sands tailings waste. Existing Problem: During the extraction of bitumen from oil sands, tailings are produced as a waste product. These tailings are a mixture of water, fines, ultra-fines, various toxic chemicals such as heavy metals, and a small number of leftover hydrocarbons, such as bitumen [3]. Current technology and economics are prohibitive for removal/separation/extraction of oil and water greater than 65% of from oil sands tailings; a byproduct of heavy oil production. Decade long timelines are required for current separation processes. Different methods may be used to extract the oil and water from the tailings. Each method follows guidelines as set by the Alberta Energy Regulators (AER) [2] and Canada’s Oil Sands Innovation Alliance (COSIA). The most common methods include thin-lift drying, the use of flocculants, or centrifugal forces. Tailings are small particles which take large amounts of time to settle out of emulsion byproducts. 65-70% solids w/w is required for reuse, but separation over 30% w/w is an industry challenge [1] Summary: BC-3 chemical is a protein-based water soluble, nontoxic, nonvolatile, nonflammable, and biodegradable chemical. BC chemicals have the ability to disrupt the hydrocarbon-hydrocarbon solubility interaction that forms crude oil. This proprietary uniqueness of chemical and bubbles yields the ability to reduce overall crude viscosity as it penetrates and adsorbs into the matrix of the formation, thus permitting rapid removal of heavy oil and water from tailings solids. The bubbles generated are Nanobubbles which break apart oil and solids more efficiently. More bubbles change the density of water and create gas saturation causing oil to rise and may be skimmed off. The solids to fall to bottom and may become reclaimed. The mixing process of BC chemicals and Nanobubbles encourages separation and extraction of solids, oil, water. Principal Uses: As tailings are abundant and labeled an environmental hazard, remediation pressure exists on mining industries and oil sand operations. Supervised reclamation happens slowly, resources run thin, and economically available technologies are common hurdles. Technical Features: Proven acceleration separating heavy oil, tailings’ solids, and entrained water, can be achieved with this proprietary innovation. Using BC Chemical, Nanobubbles, and a mechanical process rapid, economic, long-term separation/remediation may be realized.

Canada’s Energy Future 2020 report stated that increasing energy efficiency and the share of low-carbon energy sources will be key in decarbonizing our energy systems. For the fossil fuel industry, this requires pathways that adopts clean technologies and environmental value additions without compromising economics in a lower price environment. A technology solution that reduces the emissions intensity of fossil fuel production and distribution in an economic way is waste heat recovery (WHR). Contrary to high-grade heat that is used in industrial processes, “waste heat” or heat lower than 500 °C is a by-product of operational inefficiencies that is often vented to atmosphere. This waste heat can be a powerful resource when captured using Organic Rankine Cycle (ORC) systems to produce emission-free, baseload electricity. Terrapin presents the variables and considerations of this technology integration. As an externally heated, closed cycle heat engine that uses an organic two-phase working fluid, the ORC is similar to the steam-based Rankine Cycle (SRC) but is optimized to work with lower temperature heat sources in the 120 °C-500 °C range. When integrating this technology into industrial facilities, waste heat resource owners should consider: • Waste heat stream characteristics • Project site characteristics and supporting infrastructure • Power and offset markets • Jurisdictional mandates and incentives This presentation walks through the complexities of developing waste heat to power projects and the optimal characteristics of an economic deployment of ORC technology. Terrapin presents two case studies of WHR to showcase the different outputs of projects that utilize lower temperature waste heat and higher temperature waste heat. Both case studies show inherent conversion opportunities, with the greatest value being derived from waste heat to power projects developed at existing natural gas turbine infrastructure. Today, ORC installations are primarily in Europe, recovering low-temperature heat from sources such as combustion turbine and reciprocating engine exhaust, industrial furnace exhaust, geothermal resources, and biomass combustion. Adoption of ORC technology in North America has been comparably slow, restrained by low-priced electricity and natural gas, despite the presence of a significant resource in the energy industry. Current shifts in North American emission policies and standards and the further development of the technology have begun to drive increased ORC adoption rates. The combustion turbine market alone is considerable. In Alberta and British Columbia combined, there is over 1,100 MW of installed pipeline compression. If 50% of this capacity utilized WHR with ORC, 175 MW could be recovered and used on site or supplied to the grid. For the waste heat resource owner, these projects can achieve a payback of 5 years under the right conditions. Incorporating ORC heat recovery into projects with 20-year lifespans can generate a considerable return for the owner, increase facility resilience, and lower carbon footprints.

Nanobubbles (NBs) are nanoscale gaseous domains than can exist in bulk liquids or at their solid surfaces. Their appearance in aqueous solutions has attracted significant recent attention due to their apparent long-time stability (over timescales of months), and high potential for real-world applications by allowing for significantly enhance amounts of gas to be available in solution. However, the generation of NBs has proven to be somewhat difficult and energy intensive, for example involving intense agitation of solutions, ultrasonic treatment, or using microfluidic flows, with only modest concentrations of NBs achievable. Thus, to this point their potential applications have been effectively severely limited. Although surface NBs have been generated and observed using various experimental methods, bulk-liquid NBs have been much less investigated. Arguments based on Laplace pressure considerations would suggest that bulk NBs should be very transient features in solution, so the origins of their apparent stability has remained elusive. NBs are known to usually possess negative zeta potentials, resulting in mutual repulsions that are sufficiently large to prevent coalescence and slow any buoyancy rise. To explain this behaviour, it has been conjectured that NBs feature a build-up of anions (i.e. OH-) at the gas/liquid interface, yet observations of stable NBs in highly pure water suggest an alternative explanation is needed. In this presentation, we will demonstrate a novel and very recently reported method that utilizes electric fields to catalyze the massive and rapid generate of methane, oxygen, and carbon dioxide NBs in bulk aqueous solution with low energy input (1000x less than current conventional approaches). Using appropriate experimental probes, for example Dynamic Light Scattering, we characterize the NBs present and confirm their long-time stability. Using both molecular simulations and theoretical development, we also provide a consistent explanation for the apparent stability of aqueous NBs and their measured zeta potentials that does not require the presence of OH- ions. This explanation identifies unique features of the air-water interface as the origins for NB behaviour. The work has been published in Science Advances (2020; 6:eaaz0094). By achieving massive enhancement of bulk-NB formation in water, we are able to realize dramatically elevated levels of gas solubility in water many times the Henry’s-Law solubility. A groundbreaking aspect now possible will be the generation of nanoporous liquids, a new material with unique tunable properties, arising from solutions with high NB concentrations (>1% by volume). This discovery is expected to have enormous ramifications in, for example, wastewater-treatment and process industries, in addition to dramatically accelerating gas-(diffusion)-limited processes. The realization of nano-porous liquids (in the form of gas NBs in water) in a simple, facile and energy efficient manner will open up numerous opportunities across the spectrum of energy industries.

As the economy decarbonizes, the role of natural gas changes. Initially it replaces higher-carbon fuels in baseload generation, but it evolves to providing reliability to the renewables fleet. As renewables increase their share of generation, some jurisdictions are considering what role, if any, natural gas plays in a deeply decarbonized economy. My presentation explores this issue by considering the challenges and costs of eliminating natural gas from our electrical system, and how this compares with other alternatives to decarbonize.
Much of my presentation will be based on research from the Roosevelt Project, an effort within the Center for Energy and Environmental Policy Research (CEEPR) at the Massachusetts Institute of Technology “to provide an analytical basis for charting a path to a low carbon economy in a way that promotes high quality job growth, minimizes worker and community dislocation, and harnesses the benefits of energy technologies for regional economic development.” To be clear, I am making my own argument on the role of natural gas and using the research materials to support my case.
The reliability that natural gas provides to our electric system is difficult and costly to replace. While technically possible, achieving net zero in a reasonable timeframe will probably be far more costly without natural gas. Natural gas, particularly abated natural gas, should be an important part of the drive to deeply decarbonize the economy.