As the vast majority of offshore well pads and platforms are unmanned and remote, direct detection and confirmation of oil leaks can take hours or days. Such leaks have immediate and direct impacts on the environment and can expand and travel long distances in a short time. Immediate action is therefore critical in plugging the leak source and containing further spread to protect marine life and fishing industries key to the economy. Together with these ecological goals, regulatory compliance, higher HSE best practice standards, financial risk reduction (clean-up bills, penalties, inefficiencies) and safeguarding of reputational image are key factors driving the development of better leak detection technologies. The presentation will offer insight into the application of thermography (using uncooled microbolometer) powered by edge-based artificial intelligence at remote platforms to automate detection of leaks as soon as they start and provide operators with tools to visually validate alarms quickly and cost effectively. The technology capabilities, installation process and set up configuration recommendations will also be covered. Analytic thermal imaging is a relatively new, non-traditional fluid leak detection method adopted in recent years by major oil and gas operators in North America. The site-installed technology is being used to continuously and autonomously monitor above-ground onshore facilities, including pump stations and pig launching/receiving assets, and has clocked in 350,000 of field hours. The system looks for a temperature change in the scene and analyzes leak characteristics in real time using patented and proprietary image processing software, and generates alerts (with photo and video) for validated events. An evaluation commissioned by a global operator in the Gulf of Thailand led to the installation of this fully automated computer vision solution in mid-2019 for 24/7 offshore well pad monitoring. The process of installing the thermographic leak detection system involved the following stages: risk analysis and identification of high priority well pads, site evaluation to determine coverage and camera requirements (potential placement locations, field of view, etc.), system set up with testing (leak simulation using water), two to three weeks of calibration, and training of operators and administrators. All installed systems are currently running without downtime, resulting in a low/no maintenance solution to date. Leaks, large and small (as little as 1L/s), can be detected and alarmed on in less than 30 seconds, and visually verified offsite within a minute. Due to low false alarm rates, operators can easily manage this additional solution without requiring additional resources. There are other advantages of using the system. These include the incorporation of a fixed low-cost color camera for routine visual checks reducing boat trips and manpower, low bandwidth consumption from only transmitting alarms rather than continuous raw data, integrating security/intrusion analytics, and distributed assets monitoring. Thermal sensors coupled with background learning AI provides leak detection and asset condition monitoring across a wide visual area, which may not have sufficient monitoring means. This aligns with the industry best practice of deploying multiple technology solutions to achieve a more complete or overlapping coverage. The application note will educate operators on the specifics of this new and automated solution, the installation procedure, and the advantages and benefits that can be gained by augmenting their existing monitoring approaches with round-the-clock eyes on site.

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.

As leading OEMs in the energy transition, Jenbacher and Waukesha develop ways to provide a clean energy future for our customers. Both engine lines offer extensive advantages for companies looking to meet ESG demands from the presence of climate change, governmental agencies, and investors. This presentation will focus on these new technologies and highlight two case studies, one for each OEM. In these case studies, customers utilized Jenbacher or Waukesha engines to meet new energy and emissions needs reliably, efficiently, and innovatively.

This paper seeks to investigate and benchmark the performance of two integrated flow schemes developed with the intent of reducing the process scope carbon emissions intensity and improving overall gas conversion efficiencies of conventional gas-to-liquids (GTL) Fischer-Tropsch (FT) synthesis processes. The presented reference case represents a conventional FT synthesis process utilizing a natural gas feedstock and autothermal reforming (ATR) unit for syngas generation. A carbon capture and sequestration (CCS) system is deployed within the process off-gas stream with the aim of abating process scope carbon emissions, representing a minimally invasive step change over more conventional FT synthesis flowsheets. In contrast, the primary study case that was developed leverages a hydrogen import generated through electrolysis, with the electrolysis power requirement supplied by the exothermic FT-synthesis process and supplemented with a renewable power source. The oxygen by-product from electrolysis is fed with natural gas to a partial oxidation (POx) unit to generate syngas for conversion within the FT synthesis loop. Furthermore, the co-production of hydrogen allows for changes in the GTL flow scheme, significantly decreasing the amount of CO2 generated. Specifically, the deployment of a POx unit reduces steam, oxygen, and fuel gas consumption when compared to more conventional reforming technologies such as ATR at the sacrifice of reduced H2:CO ratios. For the purposes of this study, the FT synthesis process was paired with a mild hydrocracker and product work-up unit to generate a mixture of naphtha, kerosene, and diesel end products. The balance of the plant systems, including steam, power, and fuel gas balances, were developed to maximize process efficiency based on the unique operating characteristics and parameters of the identified processes. Ultimately a direct comparison between the identified flow schemes is drawn wherein the presented study case exhibits an estimated gas conversion efficiency of 7,460 Standard Cubic Feed (SCF) per bbl of liquid product with a carbon conversion of 93.7%, representing a marked improvement over not only conventional FT synthesis processes but also over the presented reference case. This work ultimately demonstrates the potential benefits that can be achieved by customizing GTL designs to optimally accommodate a decarbonized hydrogen import stream. The results of this work have broader implications for not only the decarbonization of conventional GTL pathways but also less conventional waste and/or biomass to fuels processes that are similarly deficient in hydrogen, wherein analogous principles may potentially be applied to maximize product yields.

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 10**9 grid 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 changes 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 petrophysical 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 passed into 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.

In this presentation the author describes a novel approach to making hydrogen today at less than half the cost of electrolysis, with a low or negative CO2 footprint, or alternatively renewable natural gas suitable for pipelines. This is done by converting minimally prepared MSW, RDF, biomass, ICI, or C&D waste to a clean syngas, then converting the syngas to fuel with standard unit processes, fully integrated to the syngas production for minimal risk and maximum conversion efficiency. The Larsen Lam Climate Change Initiative recently announced their full funding of a unit for a MSW to hydrogen plant in California. Their selection was made after examining 60 technologies, then conducting deep due diligence for several months on the six (6) finalists. OMNI’s Gasification and Plasma Refining System (OMNI 5000TM GPRSTM) for converting waste to syngas won the competition. On Bloomberg News, Ripple founder and billionaire Chris Larsen explained that the OMNI GPRSTM solves two very important world problems, namely making energetic waste “disappear” cleanly while extracting maximum value in low carbon fuels and avoiding methane in landfills. The syngas produced by the GPRSTM can be tailored to make hydrogen, liquid fuels, or power. By avoiding methane from landfills, the CO2e footprint can be negative. CO2 capture can allow for further reduction through sequestration. To make green hydrogen, waste is first converted to syngas using OMNI’s GPRSTM. The syngas is then converted to hydrogen and CO2 using a sour gas shift reactor designed and supplied by KP Engineering. Each unit will produce approximately 5000 tonnes/year of hydrogen. The process guarantee is backed by an insurance wrap and supported by data from over a decade of demonstration at a commercial scale. Delivery is de-risked by delivery in 200 tpd shop assembled modular units and choices made to ensure high availability. Commercial projects are being engineered and manufactured for California and China, with more in the pipeline. The conference presentation will also describe a hybrid approach, that of combining the OMNI unit with electrolysis. In this scheme, oxygen from electrolysis is used directly in the OMNI unit, and waste heat from the unit increases the efficiency of the electrolyser. The hybrid system combines the best of both alternatives for a flexible, low-cost solution, with significantly better economics than the electrolyser alone. Finally, the speaker will describe how OMNI has integrated its unit with methanation to produce renewable natural gas for injection into conventional pipelines, along with a short overview of projects in Canada and the U.K.

Canada is racing to meet climate targets while producing the energy Canadians and the world needs today and in the foreseeable future. The oil sands industry is at the forefront of this energy transition, a fundamental shift away from carbon-intensive energy production.. Canada and the industry’s goal is to produce energy with net zero emissions by 2050, while sustainably addressing other important aspects of the environment. What will it take? Ground-breaking innovation and intense collaboration like the world has never seen before. Canada’s Oil Sands Innovation Alliance (COSIA) sits at the juncture of both where it drives the research and development that will be critical to sustainable energy success. Made up of an alliance of producers that represent 90% of total oil sands production, COSIA’s track record of improving environmental performance in the region is second to none. In fact, Canadian oil sands companies are recognized as world leaders when it comes to Environmental, Social, Governance (ESG) performance. COSIA’s made-in-Canada model catalyzes extreme innovation and collaboration by bringing together leading thinkers from industry, government, academia and the broader public ?" at home and abroad ?" to solve tough environmental challenges. The focus is on reducing greenhouse gas emissions, minimizing the land footprint and stepping up water and tailings management. At its launch in 2012, COSIA was considered one of the most unique models of open innovation and collaboration the world had ever seen. It still is. Think innovation such as Carbon Capture Utilization and Storage (CCUS), natural gas decarbonization technologies, boiler flue gas heat recovery, satellite-enabled measurement and management of fugitive emissions, novel In-Pit Extraction Processes (IPEP) to eliminate tailings ponds and sunlight-powered emissions capture. Even geothermal energy! Key to these breakthroughs is the sharing of expertise, resources, technologies and intellectual property that allows COSIA members to go farther, faster with less cost and less risk. These efforts drive a vast array of incremental improvements to operations, and spur development of transformational technologies. Many of these innovations offer environmental benefits to other industries and countries around the world. The results speak for themselves. • COSIA and Industry innovations have resulted in a 20 per cent reduction in GHG emissions intensity between 2009 and 2018. • Technological and operational efficiency improvements have decreased per-barrel GHG emissions by 28 per cent from 2000 to 2017. • Freshwater use intensity at in situ operations has been reduced by 47 per cent and water use intensity from the Athabasca river at mining operations reduced by 36 per cent since 2012. • To date, COSIA members have invested $1.8 billion to develop 1,143 technologies to improve tailings management and reduce industrial impacts on air, land and water. $531 million is currently dedicated to a total of 233 active projects.

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.

ALBERTAH2 CORPORATION (AH2) has developed a patent-pending system for generating hydrogen (H2) utilizing produced water as the primary feedstock. The process was designed to enhance and supplement existing oil and gas assets in Western Canada and will be of primary interest to producers interested in reducing their carbon emission intensity (CI). The key component of this modular system is the Produced Water Electrolyzer (PWE), which employs a unique two-step method to avoid the issues associated with oxygen (O2) generation at the anode of other electrolyzers. The intent of the technology is to utilize existing infrastructure and expertise in Western Canada. The PWE employs a simple, bipolar design for H2 generation in the electrolyser cell, followed by a downstream reactor for O2 generation. Resistance to the effects of both sour and hard water components have been addressed by this unique two step design. Appropriately configured, component change-out is readily and efficiently carried out on-line. Target hydrogen costs are expected to fall between those of Blue and (currently) Conventional Green Hydrogen. This technology will act as a “battery” for solar and wind installations and, as such, there has been strong support for this technology from renewable energy developers for both stand-alone and grid-based installations.

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.

Direct Contact Steam Generation (DCSG) injects both steam and hot combustion flue gases into the reservoir. Oil production is increased by reducing oil viscosity through heat while repressuring the reservoir with flue gases and improving miscibility with the CO2 that remains in the reservoir. This combination greatly improves the Steam-Oil-Ratio (SOR) for increased oil recovery as well as delivering environmental benefits related to reduced water requirements and lower emissions resulting in a much lower carbon intensity. DCSG water requirements are 13% less than OTSG methods as water is created by the combustion process, this water is then injected into the reservoir rather than lost to the atmosphere. As most of the DCSG process emissions are indirect, emissions can be further reduced by as much as 30% with the use of electric compressors. GERI’s portable DCSG system has successfully completed four heavy oil pilots in post-CHOPS wells in the Lloydminster, Canada area in partnership between GERI, a service and technology company, and major oil operators. Each pilot test included at least one steam and production cycle. For two pilots, a history matched reservoir model was first developed to assess the feasibility and approach for injection and production. A third-party multi-well CHOPS model integrated with CMG STARS simulator was used to forecast reservoir performance by history matching the oil, water and sand production data for the selected test well and several surrounding wells. The initial test was a huff/puff test followed by a second injection cycle with noticeable production gains in the offset wells resulting in a combined SOR of less than 0.6 compared to typical industry SOR of 3.0 or more. To date over 18,000 barrels of incremental oil production has been realized from the test well and surrounding offset wells. Furthermore, the field trials were able to quantify the environmental benefits. The pilot results show that DCSG used less water, with 70% of the CO2 retained in the formation. Lower SOR and CO2 retained demonstrates lower carbon intensity relative to current technologies. Based on the results of the pilots, a DCSG that injects both steam and hot combustion exhaust gases into the reservoir can be effective in other enhanced oil recovery applications. Steam Assisted Gravity Drainage (SAGD) applications include using the flue gas to re-pressurize late stage reservoir, potentially mitigating “thief zones or in combination with infill wells to connect separate heated pools. For tight oil or low permeability reservoirs, DCSG can provide energy and re-pressurize the reservoirs, but also introduce a sweep effect, thereby, increasing recovery. Although the heat impact introduced by steam may not be as great as it is on heavy oil reservoirs, it can reduce oil viscosity and increase oil mobility. A history matched multi-well reservoir model was developed on a tight and lighter reservoir, with an oil density of 20 API and average permeability of 40 md to assess the feasibility of DCSG. Simulation results showed that even with a short injection period (15 - 40 days) of steam plus flue gases, incremental oil recovery for the first year could be 3 to 4 times compared to the no-injection scenario. DCSG offers operators a novel, viable, method to economically extract currently uncoverable reservoirs at a lower carbon intensity than traditional methods. Furthermore, GERI’s portable unit can stimulate standalone or small pools with much lower capital outlay or offers for inexpensive, short term pilots to confirm the opportunity. GERI’s DCSG technology can create anywhere from 0-80% steam quality by adjusting the water rates. Although the four previously completed pilots were focused on steam injection, GERI is currently investigating testing hot water and flue gas injection into a tight reservoir with clay content.

No country can fully realize the transition to a sustainable future on its own. We must collaborate and learn from each other.

Icelandic companies and innovators are active players in the global context when it comes to developing solutions to use in the battle against climate change. Icelanders are experts in many areas, notably in utilizing renewable energy, cascaded use of geothermal, CCUS and more. Our experience has made Icelandic experts sought-after worldwide and put Iceland at the forefront of innovation in the energy and sustainability sectors.

Climate issues have no boarders, and the Icelandic expertise, knowhow and solutions can be applied anywhere. In that context we would like to gather Icelandic players on the stage in Calgary at the Global Energy Show.

Together we are stronger and together we can reach a carbon neutral, fossil fuel free and climate friendly future.

Join us for a panel discussion from our participating companies, Q&A, and networking.

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 plants and ensure the customer has a profitable “total cost of ownership”. This presentation will review the overall ZR-LNG 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 highlight how the overall lifecycle costs play an important role in ensuring the customers “total cost of ownership” is met.

Objectives/Scope Carbon dioxide (CO2) has been used as a carbon carrier for geological carbon storage. However, various shortcomings come from its physical properties, such as low carbon density at low to moderate pressure, low mass density, low viscosity, immiscibility with water, and corrosivity. This paper presents the first study of using aqueous formate solution as carbon-bearing water for carbon storage and enhanced oil recovery. Existing technologies can generate formate anions (HCOO-) via electrochemical reduction of CO2 from flue gas. Methods, Procedures, Process Properties of formate solutions in brines were measured for the first time, such as solubilities, densities, and viscosities, at different temperatures, brine compositions, and pH values. Coreflooding experiments were performed for displacement of oil by brine with/without formate. Then, numerical reservoir simulations were performed for a 3-D heterogeneous reservoir model for carbon storage and enhanced oil recovery (EOR) by aqueous formate solution and by CO2. Simulation results were used for an economic analysis of the carbon storage/EOR processes. Results, Observations, Conclusions New data indicated that the solution viscosities ranged from 5 to 11 cp at high concentrations of formate; that is, formate anions viscosify the water phase with no other chemicals. Furthermore, formate solutions with/without crushed rock samples were confirmed to be stable at different temperatures up to 90°C for months. Subsequent corefloods conclusively showed the oil displacement front was more stable with an increased formate concentration. A simulation case study showed that the two cases exhibited entirely different flow regimes; the formate injection case resulted in a greater amount of oil recovery and carbon storage, primarily because of more stable fronts of oil and water displacement. Also, aqueous formate solution did not show any potential risk of CO2 leakage to the surface since it did not involve CO2 as a carbon-bearing species and it was slightly denser than the formation brine. An economic analysis based on numerical reservoir simulations gave the equivalent cost of CO2 reduction into formate for the same net present value as the CO2 injection case, and the breakeven cost of the reaction process for the formate injection case. Novel/Additive Information This is the first time aqueous formate solution was demonstrated as both a carbon carrier and a viscosifier to reduce the carbon emission of enhanced oil recovery processes. Formate anions can be a new viscosifier that is more environmentally safe and stable at elevated temperatures than conventional polymers. Unlike CO2 injection, there is no risk of leaking CO2 from the formation to the surface. Aqueous formate solution can be used in combination of miscible or chemical EOR agents as a viscous chase fluid.

Millions of kilometres of pipelines traverse thousands of municipal jurisdictions throughout North America. These pipelines and their related facilities are located in many different contexts, from sparsely populated rural areas to high-density urban centres, but are primarily on lands not owned by the operator. While pipelines are generally underground and therefore “out of site, out of mind” to most, challenges and conflicts can arise as a result of new development in proximity to or crossing these pipelines. Many municipal jurisdictions, landowners, and developers are not fully aware of the obligations related to developing in proximity to pipeline infrastructure ? it can oftentimes be an afterthought. If a plan has already been prepared and approved without adequately considering these matters, last-minute delays, additional costs, and frustrations can occur amongst both the municipal regulator, project proponent, and pipeline operator. Early engagement, awareness, and collaboration are key to mitigating these issues and are mutually beneficial for all stakeholders, including landowners, developers, municipalities, other government agencies, and pipeline operators. B&A has created an innovative land use planning and development monitoring program which has assisted pipeline operators and municipalities with collaborative planning in proximity to pipelines since 2016. Developed in conjunction with some of Canada’s major pipeline operators, this program has been refined and automated to facilitate early awareness of land use planning and development in proximity to pipeline systems and to support collaboration between pipeline operators and development stakeholders. Key program components and processes include: • Jurisdictional and stakeholder inventories; • Stakeholder outreach and communications; • Intake and analysis of land use planning, subdivision, and development application notifications; • Spatial referencing and mapping of notification boundaries in relation to pipeline infrastructure, viewable on an interactive web map; • Analysis and data collection summarizing impacts of notification on/from pipeline infrastructure, which can be tied to spatial boundaries; • Circulation and engagement with operator SMEs to facilitate a technical review; • Distribution of response to a municipal jurisdiction and/or development stakeholder detailing recommendations and requirements specific to their application; • Analysis of data collected over time to identify program effectiveness and trends in development patterns in the proximity of pipeline infrastructure. At the heart of this program are data and information sharing. The program has been developed to share information in an efficient manner while collecting data that can support decision-making in the long term.

Total inorganic carbon (TIC) alkalinity, hardness, pH and Silica are important parameters to control hot lime softening performance for produced water treatment. At present, Imperial’s Cold Lake in-situ oil sands is relying on grab samples data collected in every four hours interval to make decisions on lime, caustic, magnesium Oxide and soda ash dosages to control Hot Lime Softeners (HLS) effluent water quality within specific targets. Online pH analyzers are proven to provide reliable measurements for some time. Online measurement of hardness and alkalinity can help optimize lime, caustic and soda ash dosages. Online analyzers have not been commonly used in the heavy oil industry, partly due to the challenge caused by high total dissolved solids, and high organic material present in the water. In this presentation, we will share online alkalinity and hardness analyzer’s trial results and performance. We tested HACH Biotechtor TOC/TIC analyzer, and HACH EZ1000 series hardness analyzer at Imperial Oil Cold Lake facility with the objectives of automating chemical adjustments and reducing reliance on frequent operator measurements. The technologies were first validated based on preliminary acceptable correlation between manual lab and online analyzer. HACH hardness analyzer was also installed at boiler feed water location to maintain acceptable water quality for once through steam generator (OTSG). Both Online TIC alkalinity analyzer and hardness analyzer’s performance are encouraging. With new installation of afterfilter effluent hardness analyzer, these will help optimize chemical dosages for HLS and achieve consistently good quality water to minimize OTSG fouling. Online TIC analyzer is in service for more than 2 years; and hardness analyzer for more than 6 months. Quarterly maintenance frequency is found to be adequate for these instruments. Several learnings were gained through the trials to make use of online analyzer’s successfully in challenging environment. The learning from the trial of these technologies will help to advance online analyzer applications for produced water hardness and alkalinity determinations. The success of online analyzers will open the door for data driven decisions based on machine learning and advanced analytics in near future.

Objectives/Scope: Lone workers go out into new, and often hazardous locations, with little to no support to aid them. Historically, they have run into many dangers and lives have been lost in their attempts to complete tasks that power and move the world around us. This no longer needs to be the case. Through connected technologies, wearable devices, automated hazard sensing, and notifications and workflows, organizations can integrate a wide range of already fielded and new solutions that not only make lone work safer, but ease the job while improving quality, productivity and more. Currently, most of these solutions rely on smart phones and tablet, not purpose-built for the tasks of lone work in the petroleum industry. This means technologies like GPS, WiFi, 4G/cellular, and Bluetooth ? that enable consumer and enterprise connectivity ?" often fall woefully short in lone worker protection applications. In this presentation we will showcase/discuss the emerging technologies changing the game for lone worker safety, including: • Heads-up, hands free remote expert support • Real-time hazard monitoring and alerts • Environmental and biometric monitoring • Location and GIS ?" for real-time insights • Emerging integrations across devices, operational and safety dispatch systems and enterprise compliance and BI systems Methods, Procedures, Process: This will be a conversational presentation between end-users and Guardhat technologist covering the state of lone worker safety, threats/obstacles in the field and at corporate HQ, and demos of cutting-edge connected wearable technologies and a lone worker solution. Followed by a prompted Q&A session on the topic of lone worker solutions in energy. Results, Observations, Conclusions: The International Data Corporation (IDC) reports that in 2020 there were approximately 78.5 million lone or remote workers the United States alone, with a global estimate of approximately 1.3 billion in 2015. This has only been made more complicated by the Covid-19 pandemic. Regardless of what tools are used, investing effective worker safety is never a waste of money. Hundreds of lone and remote workers across North America, and across many industries, employ connected worker tools to protect themselves and their team, finding it a cost- and safety-effective solution to their lone worker-safety challenges. Novel/Additive Information: This presentation provides new and innovative methods for dealing with lone worker safety by utilizing advanced technologies with a people-centric approach. It informs and educates the audience of different and innovative solutions present in the markets today for protecting and enhancing their lone worker personnel.

Methane has a greenhouse gas intensity 25 times greater than CO2. According to the IEA, methane venting from pneumatic devices in the oil and gas industry is responsible for 532.5 million tonnes of CO2e per year, the equivalent of all emissions from 22% of the world’s coal fired power plants . Historically, a lack of cost-effective power generation solutions and the resulting high cost to deploy instrument air on remote sites has been one of the root causes of our industry’s legacy of venting gas to atmosphere through pneumatic devices. In July 2020, Westgen Technologies Inc. in conjunction with Emissions Reduction Alberta, Sustainable Technology Development Canada, and ten Canadian oil and gas companies undertook a project to develop and demonstrate a solution for eliminating methane venting from pneumatics on legacy wellsites in Alberta. The EPOD-Mini system, based on Westgen’s Global Energy Award winning EPOD power generation technology, presents an opportunity for emissions reductions projects with positive economics based on carbon credits and fuel gas expense savings. The project started with a desktop study of pneumatics inventory data from hundreds of wellsites. Crews were then deployed to the field to measure emissions rates and compare them against estimates. This data was used to inform design conditions to cover a large of variety of wellsite configurations. The next phase of the project involved deployment of EPOD units equipped with an array of sensors and measurement devices. Real time data was collected from the EPODs on variables such as peak and average air compressor flow rates, compressor run times, and energy usage. Oil sampling and lab analysis was completed to understand performance of the engine while burning variable composition raw well gas. Westgen applied the learnings from each phase of the project to develop the EPOD-Mini in 2021. In the final phase of the project, EPOD-Minis were deployed to remote wellsites for testing. The units were closely monitored throughout 2021 to gather learnings and inform product improvements. The Westgen team compiled data generated through the project to outline the technical and commercial case for instrument air retrofits. Learnings to be shared will include delineation of applicable sites, reliability metrics, cost estimates, and projected economic returns by site type. Westgen believes that this Alberta case study will have broad applicability and will inspire jurisdictions across the globe to follow Alberta’s lead in eliminating this significant environment impact of our industry.

Objectives/Scope: A surface safety valve (SSV) provides an immediate closure of the well in the event of an emergency. The actuated SSV is commonly controlled through a hydraulic circuit to open and close the valve. This circuit is composed of control elements that automatically trigger an Emergency Shutdown (ESD). Failure of the SSV or any of its control elements can delay or prevent the shutdown. The reliability of the SSV system has been managed through routine in-person visual inspection, which contributes to higher operational cost and worker safety incidents. In recent years, reduction in operational cost while maintaining (or improving) safety and production efficiency has become an industry requirement. This presentation discusses the recent development of a self-contained electro-hydraulic actuated SSV with an autonomous remote condition monitoring system. Methods, Procedures, Process: The developed system is instrumented with multiple sensors including pressure transmitters, position transmitter, temperature sensor, and hydraulic reservoir level switch in a Class I Division 1 environment and is connected to a datalogger and process controller in a Class I Division 2 environment. The process controller includes an on-board logic software and connects to a wireless transmitter receiver. This system, fully developed and tested at Stream-Flo Group of Companies, is capable of logging data at high frequency during an ESD event to provide an evaluation of the condition of the SSV and its control elements using Edge Computing. This automated approach only sends critical data remotely after performing necessary computation, thus optimizing telemetry bandwidth and power usage. Results, Observations, Conclusions: Logged sensor data was used to evaluate the time-based response of the valve position, actuator pressure, signal pressure, and temperature under different applied line pressures. Diagnostic algorithms were developed to evaluate the response time and pressure signatures during valve full and partial stroking to be used towards predicting potential SSV component and system failure. The response time of the solenoid valve (SOV), as a control element, during valve closing exhibited a relatively fast response of around 60 ms. Also, a distinctive signal pressure signature was observed for each tripping method; SOV, mechanical pilot, and manual over-ride (MOV). Valve diagnostic parameters were evaluated including actuator pressure/position hysteresis, break-to-open (BTO) pressure, and break-to-close (BTC) pressure. These results demonstrate the ability to monitor and provide digitalized feedback for real-time condition monitoring towards autonomous predictive maintenance. Novel/Additive Information: Most published SSV condition monitoring efforts focus on the process valve health with less attention to the actuator signal control circuit, which is a critical element without which an SSV will fail to close or open upon demand. The work presented in this paper demonstrates the successful in-house integration of an electro-hydraulic actuated SSV with instrumentation and control logic to develop an autonomous condition monitored SSV.

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.

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).

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.

Oil & Gas companies face mounting pressure from all sides to achieve net-zero greenhouse gas emissions. Solving this problem 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 emissions while at the same time offer sizeable returns on investment to the operator. Electric motors are the workhorses in a pipeline and processing facility. 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. Finally, MV drives that are treated with special enclosures eliminate the need for HVAC and thereby eliminate the energy consumption arising from the operation of the HVAC and the corresponding emissions to maintain the built environment around the VFD. In this presentation, we give an overview of the several practical solutions that MV drives can bring to overall sustainability of operations. The risks of not thinking about large VFDs as a strategic piece of equipment to reduce carbon emissions and electric costs in an environment of climate change pressures have become too large to ignore.

Every year oil and gas wells worldwide leak millions of tons of greenhouse gases into the atmosphere and groundwater. Traditional technologies, such as cements, are ineffective 20-30% of the time due to their inability to seal tiny fissures and micro annuli that leak gas. A series of carbon sequestration projects undertaken by researchers at Montana State University and funded by the U.S. Department of Energy explored the viability of biomineralization as a solution to this issue. Biomineralization is the process by which living organisms produce minerals. Research for this project focused on common, naturally occurring soil bacteria, which produce crystalline calcium carbonate under certain conditions. These bacteria were chosen for the project for their non-hazardous nature and the strength & bond of the mineral they produce. A low-viscosity mineralizing fluid (1.05 cP) composed of widely available food-grade chemicals is also used in the process. Laboratory research proved encouraging as biomineralization was able to effectively seal fractures in a simulated cement/steel interface with fracture width varying from two microns to four millimeters. This project culminated in several successful field demonstrations on test wells in Alabama and Indiana which proved the technology could seal micro-fractures and eliminate annular gas leakage. At the conclusion of this highly successful collaboration, three engineers involved in the project formed BioSqueeze Inc. which has since commercialized this technology and eliminated annular casing pressure in over 40 wells in six states throughout the U.S. The following example demonstrates the potential of this technology to solve this increasingly important issue. A Pennsylvania gas well scheduled to be plugged and abandoned was leaking methane from both the 13”x 9” and the 9”x 7” cemented annuli. Pressure was 55 psi on the outside annulus and 85 psi on the inside annulus. At a depth of approximately 500 feet multiple circumferential notches were cut through both casing strings all the way to the formation to allow fluid injection into the annuli. After 1.5 days of treatment, the biomineralization fluid injection rate dropped by several orders of magnitude. Subsequent monitoring by a state regulator, determined surface pressure had been reduced to zero and there were no escaping hydrocarbons. The well was then approved for permanent abandonment.

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?

The industrial nature of the Energy Sector means that even small improvements in measuring, monitoring, and controlling a system can significantly impact safety, reliability, and operating costs. Machine learning is an excellent vehicle for making these small improvements in daily operations, leading to tremendous outcomes. Willowglen Systems will highlight the value of machine learning with a 2020 Canadian case study. We will share how we reduced the cost of operating a pipeline by 28.5%! Machine learning (ML) enhanced decision support is becoming popular across a variety of industries. Given Willowglen's 50 year history in SCADA for oil and gas, applying ML to a pipeline was a logical next step combining our domain experience with this new form of automation. Also, the nature of pipelines lends itself particularly well to the use of ML decision support. Operators must consider a multitude of ever changing operational variables when managing flow rates. Even senior operators cannot be expected to control the infrastructure for optimal performance in all conditions. Decision support gives the operator the recommendations necessary for optimized flow management. We will step the audience through the process we took to successfully deploy ML models for pipelines in Canada and the US. It starts with identifying the goals, needs, or pain points of the operation. All organizations would like to lower their total cost of operations. However, for pipelines, other requirements can include decreasing the quantity of drag reducing agent (DRA) used, increasing safety, reducing electricity usage, maximizing throughput, and more holistic operator training. Next is the value assessment. Given the organization's goals, we receive 12 months of data, build an ML model, and test the model's ability to make predictions. It's important to share with the organization an estimate of the impact the ML model will have. For example, in our recent ML project's value assessment, we estimated cost savings of 20-40% for the pipeline. If the value assessment is appealing to a company, we move forward in deploying the model. Deploying ML models is dependent on the comfort level of the organization and anticipating that comfort levels will change over time. There are three key ways to deploy an ML model ranging from decision support to autonomous optimization. The first way is manual, running parallel in the system as a final check. Secondly, is semi-autonomous, where the model is integrated and changes pop up as a confirmation or notification for the operator. Thirdly, is autonomous, which allows the model to optimizes decisions and change settings accordingly. Artificial intelligence, ML, and automation integrated with SCADA is a significant trend we see across multiple industries. The whole Energy Sector, not just pipelines, could greatly benefit from ML models. Just think, if a single pipeline with six pumps can realize savings of over $1 million every year, what could you be saving?

Monitoring methane emissions from oil and gas facilities requires the combination of several technologies to gain a full understanding of the challenge at a manageable cost. The integration of frequent and affordable high resolution satellite measurements to find the larger leaks with less frequent aircraft surveys, forms the basis of a tiered monitoring system showing great promise to optimize Leak Detection and Repair (LDAR) activities. We will present examples of methane emissions measurements at oil and gas facilities acquired with both GHGSat’s second satellite, Iris (launched in September 2020) and the airborne variant with the imaging spectrometer design. While the combination of different technologies is not uncommon, this system is the first in the world utilizing the same sensor concept at two different altitudes. The performance parameters of each system will be highlighted and supported with recent examples. In addition, the advantages of the hybrid system will be discussed, including the opportunity for cross-validation of measurements. Finally, the potential of such a system to be used for regulatory reporting purposes will be discussed and contrasted to the standard of performing Optical Gas Imaging (OGI) camera campaigns three times a year used in jurisdictions, such as in Canada and the US.

Although there is an effort to implement the best project management practices worldwide, energy projects experience difficulties meeting the three successful criteria; delivered on time, with a final actual cost on or below budget, and in full compliance with the technical and regulatory requirements. 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 industry. Two 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 starts by determining the project scope with a 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. Both are credited as work packages are completed using the binary theory. Using this theory, it is possible to implement a simplified approach by crediting value only for the physical work completed, increasing objectivity in determining the project percent complete and forecasting the final cost and completion date during construction. Combining a 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 integrated planning and construction methodology also enables monitoring programs and portfolios more effectively due to the consistency in recording productivity and efficiency indices (CPI and SPIt, respectively), project percent complete, and forecasts of final cost and completion date when closing each measurement reporting period during the construction phase of energy projects. This integrated planning and construction methodology was developed to encourage private companies and government organizations to make changes to the way construction projects are handled nowadays to track margins, improve performance, and increase profits. It also represents an opportunity to reduce waste by adopting the Lean Construction approach and measure performance by implementing the LEED rating system. The main challenge is to overcome current common practices during the planning and construction phases of energy projects.

The oil and natural gas industry includes a wide range of operations and equipment, from wells to natural gas gathering lines and processing facilities, to storage tanks, and transmission and distribution pipelines. The industry is a significant source of emissions of methane, a potent greenhouse gas. In order to reduce methane emissions, operators must regularly monitor their entire network to detect methane leaks. A reliable gas identification and quantification imaging system represents an upgrade to the current gas detection technologies. Infrared hyperspectral imaging can visualize fugitive emissions and gas leaks under various environmental conditions and industrial contexts. Aerial gas detection and quantification is an efficient way to survey large assets for possible leaks. This work will present the methane emission detection and quantification capabilities of Telops’ Hyper-Cam Airborne mini an airborne hyperspectral imaging system. The system weights less than 24 kg which makes it perfectly suitable for ultralight aircraft and drones, thus allowing to cover large areas in less time compared to helicopter mounted solutions, hence lowering operational cost. The flexibility of the system allows to tailor and optimize parameters based on the application of interest, either the the methane distribution or production sectors. In flight the system dynamically adapts to ever changing flight conditions. Data acquisition is fully automated requiring minimal to no operator intervention. Detection and quantification reporting is done in real-time which allows rapid and critical decision making. The data presented comes from controlled releases of methane at flow rates between 1,8 to 1,082 kg per hour conducted over various sites over the last 3 years. At the detection limit determined from the results, the system is able to detect 90% of the emissions found by Omara et al. in 2018 and ~100% of the ones found by Cusworth et al. in 2021. Using measured wind data, it is possible to calculate leak rate values and compare them to commanded leak rate values. Results show excellent correlation with a fitted slope of 0.99 (1 would be perfect correlation) and a R2 value of 0.89. In addition, the collected data spans a wide range of atmospheric conditions and flight parameters. This paper will also include a discussion on how methane detection and leak rate quantification accuracy depends on the atmospheric conditions.