Abstract The Oil and Gas industry today faces the ȢEnergy Trilemma,Ȣ that is satisfying the growing global demand for energy, in conjunction with increasing societal pressure to decarbonise whilst also reducing costs. The decarbonisation of Oil and Gas assets is often perceived to be a capital-intensive process, which will make operations more difficult and impact profitability. Whilst this may be true for the more aggressive/ambitious mitigation schemes, there are solutions that can significantly improve the bottom line. Many of these solutions can be easily implemented, without significant disruption, and result present material GHG reductions. This paper highlights the opportunities for Oil and Gas operators to identify, fund, and execute energy transition projects that have successfully decarbonised assets. The decarbonisation methodology builds on lessons learned in identifying low carbon transition pathways for other high emitting industries. The process begins with a framework and evaluation model to assess a wide set of potential carbon reduction technologies that Oil and Gas companies can use to achieve carbon reduction. The key evaluation and prioritisation tool is the marginal abatement model which incorporates low carbon transition scenario planning with extended functionality aimed at providing insights to successfully achieve the targeted reduction and the potential impact of these scenarios on future financial performance. Following the evaluation and prioritisation methodology, this paper will review two decarbonisation case studies that have identified positive cashflow outcomes. The first is the application of a hybrid energy system installed at a remote onshore site to reduce reliance on diesel. The second considers reductions in the cold venting operations on a complex offshore facility to reduce fugitive emissions. The first case study demonstrates how an energy transition programme resulted in the phased delivery of a complete hybrid energy system which integrated wind power, diesel generation, and several energy storage systems including hydrogen electrolysis, storage and fuels cells, as well as lithium ion batteries and flywheel technology, all managed by a custom microgrid controller to power this remote production site whilst reducing GHG emissions. This case study shows how experience and investment in another industry can be exploited in the Oil and Gas industry. The lessons from the first phase were applied to make the second phase more economic, resulting in significant operating cost savings and the reduction in GHG emissions is 10,530 tCO 2 -eq per annum. The second case study offers an approach to decarbonisation which can be applied more generally in the context of operational efficiency. The ease with which the project can be executed was also assessed to ensure minimum operational downtime during the implementation phase. Our paper concludes that energy transition initiatives, if approached by combining deep techno-economical expertise, coupled with the experience from a wide range of industries, can provide attractive commercial opportunities for upstream and midstream operators. These projects whist meeting decarbonisation goals also make suitable candidates for emerging energy transition financing initiatives.

Abstract Net Energy Analysis (NEA) provides essential information and insight that can be used to support field level decision making by oil and gas owner/operators. It contains important information that compliments traditional field level analytical methods that take into account operational and capital expense (OPEX and CAPEX) estimates, discounted cash flows, production volumes and recoverable reserves. The objective of this research is to describe practical methods of conducting field-level NEA and demonstrate the benefits via thought-provoking hypothetical case studies. One way to integrate NEA and economics is through the use of Energy Intensity Ratios (EIR) at the field level, which focuses on the ratio of the energy costs to the energy intensity of a field, two critical factors affecting both a field's economics and environmental impact. To begin with, this ratio is developed for a number of diverse hypothetical fields and provides an insightful comparison of the underlying economic drivers of different production schemes. Sensitivities on the underlying energetic drivers of a field are explored, taking into account the following recovery methods: (1) water flooding with downhole pumps for production; (2) water flooding with gas lift for production; and (3) steam injection with downhole pumps for production. Additionally, the EIR concept is applied to three small oil fields located in the Gulf of Thailand, with differing energy intensities and fuel sources. The three actual fields all employ water flooding, or water disposal, with downhole pumps for production, which makes for an interesting comparison with the first hypothetical case. The field level EIR provides an interesting perspective on the economic drivers of the field and clearly differentiates between a production scheme in which the fuel is inexpensive, e.g. from unmarketable production fluids, and the energy intensity of production is low, to a field with higher fuel costs, e.g. imported power or liquid fuels, and a corresponding high energy intensity of production. This research also describes how deviations in operational expectations can have a substantial impact on the energetics, environmental impact and economics of an oil extraction development.

Abstract In line with the ADNOC HSE Policy, our goal is to minimize gas flaring to environment from Acid gas flare common for four plants as much as possible, using best available technologies. The requirement is to recover the flare gases instead of being burnt in the Acid gas flare systems during normal plant operations and compress to the required pressure for injecting back into the processing facilities at the suction of Medium Pressure (MP) Compressors. Hydrocarbon liquids and sour water separated in the Acid gas flare recovery system (AGFRS) sent to existing sour water stripper. The World Bank introduced the "Zero Routine Flaring by 2030" initiative, which serves as the foundation for our objectives to reduce acid gas flaring and recover flared gases. This is achieved by successful implementation of acid Gas Flare Recovery Systems in one of the existing ADNOC Gas Processing complexes. This paper presents the stages involved and detailed design, i.e. Study, FEED and EPC. The journey of implementing state of the art AGFRS commenced by conducting a thorough in-house study of all existing acid gas flare discharges from various operating plants in the complex, which were connected by a common acid gas flare system. After measurement and tally of flare flowrate during normal plant operations over a period, it was possible to forecast flow rates through the common acid gas flare header for various scenarios. The in-house study and analysis indicated potential recovery of approximately 1-3 MMSCFD of gas from existing operating plants. This study prompted subsequent FEED and EPC detailed design phases, with HAZOP and SIL sessions to derive an inherently safe design to overcome implementation challenges. The project successfully commissioned in September 2014. The AGFR system found to be capable of operating at flowrates up to the design flowrate across the full range of molecular weights. The predicted recovery of acid gas was in the range of 1-3 MMSCFD. However, the actual average annual recovery of acid gas for a period of five years, after commissioning of the project, 2.5-3.27 MMSCFD for the period 2015-2019. Total Cost benefits for a period of five full years (Jan 2015 to Dec 2019) accumulate to US$ 14 MM (Basis: 2.61 US $/MMBTU, 1000 BTU/SCF). Total saving of CO2 emissions for a period of five full years (Jan 2015 to Dec 2019) accumulate to 325 KT (Basis: 140 billion cubic meters annually = 300 million Tonnes of CO2, 1MMSCFD= 22.14 KT of CO2/year). The acid Gas Flare recovery unit has helped to achieve significant benefits by minimizing acid gas flaring to the environment and thereby reducing the carbon footprint in support of environmental norms, while still maintaining process safety for the existing plants. The successful implementation of AGFRS is first of its kind within ADNOC Gas Processing. The project demonstrates tangible benefits to minimize continuous flaring with an operational record of accomplishment of nearly five continuous years. The experience demonstrates that it offers reliable means to recover acid gases across a wide range of gas compositions without affecting the safety of the existing facilities and thus achieves 100% HSE, and increases profitability with a reduced environmental impact.

Abstract The production of hazardous gases such as CO 2 and H 2 S impose high risks to offshore operations, with lethal impacts on personnel, along with special equipment required and environmental challenges. Hydrocarbon productions require that part of this gas could disperse on the atmosphere, so a comprehensive risk analysis is necessary to evaluate the gas disposal event. Computational Fluid Dynamic (CFD) can be used to effective study how the wind and environment can interfere with the gas dissipation in the air. In this work, a specific analysis was necessary to produce a gas well with up to 80% CO 2 fluid composition. A CFD Gas Dispersion Analysis evaluated the turbulent airflow over and offshore drilling vessel perimeter to map the flammability levels and hazardous gases concentration zones, depending on winds speeds, wind directions, and well gas flowrates. Parallel processing was applied in order to reduce the computing time for simulation of 52 cases on gas release on burner booms and relief lines, and 56 cases for leak analysis on the process plant. The results permitted defining using 3D maps the concentration levels of hazardous gases on the rig expected on each scenario condition, as well as the coverage area outside the vessel affected by the gas release.

Our planet has a tremendous problem with the air pollution and climate change. The last study published by Jos Lelieveld et al. [ 1 ] remarks the high exposition risk of EU Citizens to suffer cardiovascular diseases due to our poisonous air quality, killing yearly 800.000 EU citizens and reducing 2.2 years our life expectancy. Additionally, the last report presented on the UN conference for climate change on 25th of September'19, the IPPC, sets that if the water temperature increases 2°C, the sea level will rise 42cm from this year to 2100 but. If it increases 3°C, the rise will be 84 cm. Besides, it has been demonstrated that the carbon footprint associated with various human activities leads to a steady increase in global mean temperature. Most of the gases that human activity emits into the atmosphere are due to the industrial processes that require a lot of energy for the transformation of the raw materials. Furthermore, a large part of the energy consumed in the industry is dissipated in the form of heat, also called waste heat. As a clear example, in the EU27, it is estimated that more than 65% of the energy used in the energy-intensive industries (EII) industry is lost in form of waste heat, representing yearly the 21% the EU energy needs. This paper presents new wireless and battery-less industrial Internet of Things (IIoT) devices powered by waste heat for measuring vibrations in rotative machines, called INDUEYE IIoT. These self-powered devices will help huge energy demanding industries (especially chemical, petrochemical, oil refineries, etc.) to become more environmentally friendly and profitable in their digitalization process towards Industry 4.0. Also, these new industrial sensing devices take benefit of the new long-range wireless protocols such as NB-IoT or LoRa that simply eliminate all the wireless infrastructure in the facility (and its associated costs). Additionally, the edge-computing concept is introduced in the INDUEYE IIoT device decreasing to 98% of the cloud computation, reducing in consequence, the cloud computing carbon footprint, and its associated fees.

Following the trend of energy efficiency, the Oil&Gas sector is looking continuously to sustainable solutions aimed to reduce carbon footprint while maintaining competitiveness. The market shows that a clever way for O&G field is the implementation of Organic Rankine Cycle technology, which turns waste-heat into useful power, with minimum impact on the existing facilities. An ORC unit can exploit waste heat from several sources. Different ORC applications within the O&G field were studied. The study conducted evolved in two phases. The first one aimed to identify the most suitable waste heat sources unexploited in the O&G facilities. The second one explored the technical and economic analysis of different configurations, in order to understand the best ORC solution for this industrial sector (in terms of process parameters, equipment and layout). A proved ORC application was in the Gas-compressor-stations along the pipelines where multiple gas-turbines operating in open-cycle are used as prime-movers for compressors. Although reliable and flexible, they waste a significant amount of energy that can be converted into useful power by means of an ORC system, a clear opportunity to boost the overall efficiency of the plant. Other applications regarded the exploitation of hot streams in associated petroleum gas (APG) process carried-out within refineries. Due to its poor chemical composition, APG are typically burned via torches, thus wasted. ORC can exploit that energy to produce electricity by means of a flare-gas-boiler which heats up a vector fluid to feed the turbogenerator. Beside those waste-heat streams, another potential form of energy was available in gas pressure-letdown stations, where lamination valves dissipate the potential energy contained in the pressurized gas. In this scenario, the Gas-expander technology (similar to ORC) can be a valuable alternative and a more efficient solution. It consists in a turbine through which the NG at high pressure, rather than being laminated, expands to produce work, thereafter converted into electricity by a generator. This paper will present the above-mentioned solutions, employed both individually or combined. Considering a large-scale application, the paper will show how the implementation of the ORC recovery systems represents other than a way to meet sustainability targets also a remarkable and profitable business for O&G companies. Furthermore, the Gas Expander technology represents a solution to improve the energy efficiency of NG transmission and distribution networks, as well as upstream and downstream facilities.

The Oil and Gas industry today faces the ȢEnergy Trilemma,Ȣ that is satisfying the growing global demand for energy, in conjunction with increasing societal pressure to decarbonise whilst also reducing costs. The decarbonisation of Oil and Gas assets is often perceived to be a capital-intensive process, which will make operations more difficult and impact profitability. Whilst this may be true for the more aggressive/ambitious mitigation schemes, there are solutions that can significantly improve the bottom line. Many of these solutions can be easily implemented, without significant disruption, and result present material GHG reductions. This paper highlights the opportunities for Oil and Gas operators to identify, fund, and execute energy transition projects that have successfully decarbonised assets. The decarbonisation methodology builds on lessons learned in identifying low carbon transition pathways for other high emitting industries. The process begins with a framework and evaluation model to assess a wide set of potential carbon reduction technologies that Oil and Gas companies can use to achieve carbon reduction. The key evaluation and prioritisation tool is the marginal abatement model which incorporates low carbon transition scenario planning with extended functionality aimed at providing insights to successfully achieve the targeted reduction and the potential impact of these scenarios on future financial performance. Following the evaluation and prioritisation methodology, this paper will review two decarbonisation case studies that have identified positive cashflow outcomes. The first is the application of a hybrid energy system installed at a remote onshore site to reduce reliance on diesel. The second considers reductions in the cold venting operations on a complex offshore facility to reduce fugitive emissions. The first case study demonstrates how an energy transition programme resulted in the phased delivery of a complete hybrid energy system which integrated wind power, diesel generation, and several energy storage systems including hydrogen electrolysis, storage and fuels cells, as well as lithium ion batteries and flywheel technology, all managed by a custom microgrid controller to power this remote production site whilst reducing GHG emissions. This case study shows how experience and investment in another industry can be exploited in the Oil and Gas industry. The lessons from the first phase were applied to make the second phase more economic, resulting in significant operating cost savings and the reduction in GHG emissions is 10,530 tCO 2 -eq per annum. The second case study offers an approach to decarbonisation which can be applied more generally in the context of operational efficiency. The ease with which the project can be executed was also assessed to ensure minimum operational downtime during the implementation phase. Our paper concludes that energy transition initiatives, if approached by combining deep techno-economical expertise, coupled with the experience from a wide range of industries, can provide attractive commercial opportunities for upstream and midstream operators. These projects whist meeting decarbonisation goals also make suitable candidates for emerging energy transition financing initiatives.

Global carbon emission reduction targets and how to meet them are high on operators’ agendas. Quantifying greenhouse gas (GHG) emissions created across every segment of the hydrocarbon extraction and production value chain is an essential step in this process. It's already widely acknowledged by operators on the UK Continental Shelf that drill cuttings treatment at the well site can materially reduce costs and improve safety by avoiding the need to collect, contain and transfer cuttings by sea and road freight to a specialist processing facility onshore, as required using the traditional "skip and ship" method. It's also widely accepted that by reducing the transport and logistics involved in skip and ship processing, carbon emissions are also greatly reduced, but by exactly how much had not been precisely quantified. In order to support operators’ understanding of their carbon footprints towards drilling waste management specifically, TWMA performed a study to establish the comparative carbon footprint for a portable thermal processing drill cuttings processing unit, treating drill cuttings on a standard offshore platform, versus that of a typical skip and ship to shore operation. The study investigated the carbon footprinting process, interpreted recognised guidance and set system boundaries and emission scopes. The carbon footprint associated with each method of treatment was then calculated, based on carbon dioxide equivalent (CO 2 e) per tonne of drill cuttings functional unit. Furthermore, a carbon calculator was created to establish a carbon footprint comparison capability for any well within the North Sea. The results revealed that the carbon footprint of the current skip and ship operation is 53% higher than that of a portable unit treating drill cuttings at typical North Sea well site. Furthermore, and based on the lower estimate of drill cuttings produced on the UK Continental Shelf, additional benefits will include: the diversion of 28,000 tonnes of waste powder from landfill; the recovery of 6000 m 3 of produced oil for re-use in the offshore drilling system; and 6000 m 3 of water that requires no further wastewater treatment. This study is the first of its kind to show a direct CO 2 comparison between offshore processing and the skip and ship cuttings disposal method. It has increased the awareness of the CO 2 e emissions associated with each process. As the industry moves towards a lower carbon future, it provides a solution to significantly reduce the carbon emissions of drilling operations whilst also improving safety and reducing well cost.

The production of fuel and chemicals in many countries is based on fossil sources but concerns about reservoir limitations and greenhouse gas emissions are shifting the focus towards solutions to increase the efficiency of processes and decarbonise these markets: the objective of this paper is to provide an overview on low-carbon intensity technologies that are instrumental to the decarbonisation of the energy industry. Hydrogen is the most promising low-carbon intensity energy vector. However, it is mainly produced through hydrocarbon steam reforming which generates 9 to 12 metric tons of CO 2 per ton of produced hydrogen. A key factor in driving the energy transition and achieving a low-carbon future is therefore the potential to obtain low carbon intensity hydrogen – through carbon capture solutions producing blue hydrogen, using biofeedstocks within adapted steam reforming applications to produce biohydrogen, or via water electrolysis utilizing renewable power. The blue hydrogen technology described in this paper results in more than 90% CO 2 emissions reduction due to the integration of an advanced steam reforming solution with pre-combustion carbon capture. While blue hydrogen, which is produced from hydrocarbons, is able to significantly reduce the emissions to the atmosphere, but still produces some CO 2 , biohydrogen is instead a carbon neutral solution achived via modified steam reforming of liquid biofeedstock. This technology has the potential to be carbon negative when enhanced with a carbon capture system. Another aspect of the decarbonisation process, Substitute (or Synthetic) Natural Gas (SNG) from biomass gasification, biogas upgrading and power-to-gas systems is the most promising and immediate solution among the hydrocarbon-based fuels. SNG product has great market possibilities in refining, and automotive sectors or for injecting into pipelines for the upgrading and re-purposing of distribution networks. The product is a clean carbon alternative to conventional natural gas that can be distributed using the existing grid infrastructure. Wood is pleased to present this paper to introduce the above-mentioned technologies for hydrogen and SNG, with the aim to provide viable and alternative solutions to industrial operators who are looking to support the economy decarbonisation securely and create a more sustainable future.

The production of hazardous gases such as CO 2 and H 2 S impose high risks to offshore operations, with lethal impacts on personnel, along with special equipment required and environmental challenges. Hydrocarbon productions require that part of this gas could disperse on the atmosphere, so a comprehensive risk analysis is necessary to evaluate the gas disposal event. Computational Fluid Dynamic (CFD) can be used to effective study how the wind and environment can interfere with the gas dissipation in the air. In this work, a specific analysis was necessary to produce a gas well with up to 80% CO 2 fluid composition. A CFD Gas Dispersion Analysis evaluated the turbulent airflow over and offshore drilling vessel perimeter to map the flammability levels and hazardous gases concentration zones, depending on winds speeds, wind directions, and well gas flowrates. Parallel processing was applied in order to reduce the computing time for simulation of 52 cases on gas release on burner booms and relief lines, and 56 cases for leak analysis on the process plant. The results permitted defining using 3D maps the concentration levels of hazardous gases on the rig expected on each scenario condition, as well as the coverage area outside the vessel affected by the gas release.

Net Energy Analysis (NEA) provides essential information and insight that can be used to support field level decision making by oil and gas owner/operators. It contains important information that compliments traditional field level analytical methods that take into account operational and capital expense (OPEX and CAPEX) estimates, discounted cash flows, production volumes and recoverable reserves. The objective of this research is to describe practical methods of conducting field-level NEA and demonstrate the benefits via thought-provoking hypothetical case studies. One way to integrate NEA and economics is through the use of Energy Intensity Ratios (EIR) at the field level, which focuses on the ratio of the energy costs to the energy intensity of a field, two critical factors affecting both a field's economics and environmental impact. To begin with, this ratio is developed for a number of diverse hypothetical fields and provides an insightful comparison of the underlying economic drivers of different production schemes. Sensitivities on the underlying energetic drivers of a field are explored, taking into account the following recovery methods: (1) water flooding with downhole pumps for production; (2) water flooding with gas lift for production; and (3) steam injection with downhole pumps for production. Additionally, the EIR concept is applied to three small oil fields located in the Gulf of Thailand, with differing energy intensities and fuel sources. The three actual fields all employ water flooding, or water disposal, with downhole pumps for production, which makes for an interesting comparison with the first hypothetical case. The field level EIR provides an interesting perspective on the economic drivers of the field and clearly differentiates between a production scheme in which the fuel is inexpensive, e.g. from unmarketable production fluids, and the energy intensity of production is low, to a field with higher fuel costs, e.g. imported power or liquid fuels, and a corresponding high energy intensity of production. This research also describes how deviations in operational expectations can have a substantial impact on the energetics, environmental impact and economics of an oil extraction development.

In line with the ADNOC HSE Policy, our goal is to minimize gas flaring to environment from Acid gas flare common for four plants as much as possible, using best available technologies. The requirement is to recover the flare gases instead of being burnt in the Acid gas flare systems during normal plant operations and compress to the required pressure for injecting back into the processing facilities at the suction of Medium Pressure (MP) Compressors. Hydrocarbon liquids and sour water separated in the Acid gas flare recovery system (AGFRS) sent to existing sour water stripper. The World Bank introduced the "Zero Routine Flaring by 2030" initiative, which serves as the foundation for our objectives to reduce acid gas flaring and recover flared gases. This is achieved by successful implementation of acid Gas Flare Recovery Systems in one of the existing ADNOC Gas Processing complexes. This paper presents the stages involved and detailed design, i.e. Study, FEED and EPC. The journey of implementing state of the art AGFRS commenced by conducting a thorough in-house study of all existing acid gas flare discharges from various operating plants in the complex, which were connected by a common acid gas flare system. After measurement and tally of flare flowrate during normal plant operations over a period, it was possible to forecast flow rates through the common acid gas flare header for various scenarios. The in-house study and analysis indicated potential recovery of approximately 1-3 MMSCFD of gas from existing operating plants. This study prompted subsequent FEED and EPC detailed design phases, with HAZOP and SIL sessions to derive an inherently safe design to overcome implementation challenges. The project successfully commissioned in September 2014. The AGFR system found to be capable of operating at flowrates up to the design flowrate across the full range of molecular weights. The predicted recovery of acid gas was in the range of 1-3 MMSCFD. However, the actual average annual recovery of acid gas for a period of five years, after commissioning of the project, 2.5-3.27 MMSCFD for the period 2015-2019. Total Cost benefits for a period of five full years (Jan 2015 to Dec 2019) accumulate to US$ 14 MM (Basis: 2.61 US $/MMBTU, 1000 BTU/SCF). Total saving of CO2 emissions for a period of five full years (Jan 2015 to Dec 2019) accumulate to 325 KT (Basis: 140 billion cubic meters annually = 300 million Tonnes of CO2, 1MMSCFD= 22.14 KT of CO2/year). The acid Gas Flare recovery unit has helped to achieve significant benefits by minimizing acid gas flaring to the environment and thereby reducing the carbon footprint in support of environmental norms, while still maintaining process safety for the existing plants. The successful implementation of AGFRS is first of its kind within ADNOC Gas Processing. The project demonstrates tangible benefits to minimize continuous flaring with an operational record of accomplishment of nearly five continuous years. The experience demonstrates that it offers reliable means to recover acid gases across a wide range of gas compositions without affecting the safety of the existing facilities and thus achieves 100% HSE, and increases profitability with a reduced environmental impact.

According to the IEA, the oil & gas industry can achieve a 75% reduction in methane emissions with current technologies, and up to 70% at no net cost. About 62% of the emissions CO2e is coming from upstream activities. Fugitive emissions constitute the biggest single emitting source. LDAR is therefore essential in every upstream asset. In this paper, I will discuss best practices and share case studies about how LDAR can help to minimize methane emissions. Leak Detection and Repair programs have a long history with EPA Method 21 or OGI. LDAR is crucial to prioritize maintenance activities. Although some gas companies prefer OGI because of cost reasons, the more effective detection technique for all methane emissions is still using sniffing equipment PID or FID. A comparative study indicated that only 71% of the bigger leaks with more than 262 kg/year emissions are found with OGI and only 5% of the smaller leaks. Moreover, quantification of the mass leaks becomes much more accurate with sniffing equipment compared to camera screening combined with leak/no leak factors. A best in class approach is realized with an LDAR campaign that applies Risk-Based Inspection considerations in combining measuring techniques like FID/PID and OGI and frequencies referring to the probability of occurrence and consequence of emissions (source type, historical performance, stream composition, HAP, …). Another best in class practice is situated around repair activities. While in every campaign between 10 to 20% new leaks are identified, 80 to 90% of the emitting sources were leaking in previous measuring surveys and have returned. The tightening of leaking gaskets and seals provides a temporary better emission value of more than 90% reduction in only 62% of the repair attempts. Although a typical emission reduction improvement with a thorough LDAR program of 70% is achievable, more emphasis should go to in-depth problem solving to avoid recurring leaking sources. Examples include proactive mass replacement of certain gaskets or stem valve seals during turnaround activities. This continuous improvement realized with these repair activities decreases the fugitive emissions steadily. Situations, where a yearly LDAR campaign has been omitted, demonstrate a quick return to past emission figures. Executing LDAR, finetuned to the situation and outstanding legislation, is necessary to contribute to lower methane and in general GHG emissions. Based on our experience of delivering successful Leak Detection & Repair (LDAR) in the past three (3) decades, we would like to share new technologies & approaches towards detection, quantification and reduction of Methane losses , that are being implemented by various Oil Companies across the globe. Our recommendations shall be supported by actual data we have gathered from the 8,000+ fugitive emission projects we have done in the past. Also in this paper, we would like to highlight the importance of an integrated methane emission management platform (software) to ensure a transparent, auditable and manageable Methane Emission program.

Nowadays, across the Energy Industry, there is no longer any discussion on the ‘Return of Investment’ for using drones for specific use cases such as Asset Integrity Inspections. Given the time saving, the amount of data gathered, the better use of resources and worker safety benefits, using drones for several fields of application is a ‘no brainer’ for Eni. In the last years Eni interest in using drones raised, paying now more and more attention to new fields of application such as HSE, Security, Seismic and Logistics in order to support several needs. New Hardware and Software allows performing new types of operations as listed below, but not limited to: Beyond Visual Line Of Sight (BVLOS) operations. Fully autonomous operations. Light Material transport Long range pipeline surveillance Emissions detection In order to achieve above targets Eni put in place several processes: A continuous market trends analysis in order to identify technologies, providers and services to perform new types of operation in a proper and safe manner. Analysis results are shared inside Eni and between Eni HQ and ENI Business Units with the aim to improve internal know – how. A continuous communication between Eni HQ and Eni Business Units allows identifying technologies to design in-house because of not satisfied by the market. Development of new competence and skills. Thanks to new technical competences inside Eni LOGIS Aviation competence center, Eni improves day by day the knowledge of national and international regulatory system and the collaboration with local Aviation Authorities. Release of internal regulatory documents based on international regulatory system, to define rules, guidelines and procedures with the aim to manage, standardize, support and guarantee safe, healthy and secure UAS Operations. Issue of dedicated feasibility study with cost/benefits/constraints evaluation Technical acceptance document for service providers In light of above, Eni looks to use drones in the workplace just like any other ‘tool’, don't just think of drones in terms of what we see today but think about tomorrow with interest on combination between UAS and Artificial Intelligence and UAS and IOT. The implementation of UAS operations to several fields of application and in autonomous manner can really change the way to operate in O&G industry. This will facilitate not only operations at height but also operations offshore and in remote areas, with an improvement of safety for both operators and assets, reducing time and costs.

The intensity of global warming has increased in recent years and reduction of greenhouse gases become a necessity. The Paris Agreement's recently signed by 196 countries long-term goal is to mitigate the global average temperature to well below 2 °C above pre-industrial levels ( Wikipedia, 2018 ); and to limit the increase to 1.5 °C, as this will results in controlling the risks and effects of climate change. Governments are going towards stringent regulations and implementation of carbon credits. In oil and gas industry, gas is produced with oil and it is mostly treated and transported for various industrial uses. However, a significant portion of this gas is used in the facilities for power generation and other uses. Tanks for example, are usually blanketed by fuel gas. During the operation of the tanks gases are lost due flashing, level variation and thermal variation. The gases are usually collected in a header and then flared through atmospheric gas flares. The flaring will result in higher CO 2 emission. Inefficient flares will also result in incomplete combustion of hydrocarbon and consequently the emission of methane and other gases. Currently, there are various technologies used to recover the gas, compress it and reuse it. Ejector, Eductor or compressors are mainly used for such application. Depending on the available resources, utilities, operational and maintenance experience and the return on investment any of these technologies can be selected. Daleel Petroleum LLC, who are operating a field in Oman, set a target of zero flaring by initially installing a gas treatment and compression plant to recover associated gas which was successfully commissioned in 2018. The next step is to recover the gas from the tanks, compress it and send to the gas treatment plant for further processing. This study covers Daleel petroleum LLC's approach in selecting the optimum technology for AP gas recovery and utilization. The study focused on setting the selection criteria and return on investment. A selection criteria will provide other operators with a holistic approach to take decision towards zero flaring and it will set a clear path on how to achieve it.

Long span Flare Booms are fatigue sensitive. Most of these Flares are also protected by the passive fire insulation and hence inspection of Flare structural joints for signs of fatigue cracking/damage during it's service life can result in high maintenance cost. Fatigue design is governed by selected wind speeds also called as wind blocks. It is also governed by the shape of the wind load spectrum. These two parameters viz wind speeds and wind load spectrum play a vital role influencing fatigue life. Present paper contains methodology for selection of the wind blocks. Selection of the directional dependent input parameters to a wind load spectrum is also discussed. Both these cases are studied independently to get the insight on the fatigue life impact. Ultimate aim is to ensure adequate/sufficient fatigue design life of the Flare with minimum maintenance cost.

PETRONAS Carigali Iraq BV (PCIHBV) is the Operator for an onshore oil field which is located in a 30 km x 10 km Contract Area at the southern part of the Republic of Iraq. One of the key activities undertaken by PCIHBV during the development and production campaign is well intervention which involves acid stimulation, well clean up and unloading of newly drilled wells. The conventional practice in Iraq for acid stimulation and well clean-up operation for carbonate reservoir is to burn the recovered hydrocarbon at dedicated flare pit area. This is normally followed by Multi Rate Test (MRT), which takes up to 10 hours of continuous flaring operation for each perforated zone. Some of the critical challenges posed by the above approach include managing and ensuring safe operation for personnel working in this rig-less operation. The flaring activity would release unburned oil, gas fumes, noise, heat and black smoke to the environment. Moreover, there had always been interruptions from the nearby communities who were affected by the release of fumes and smokes from the flaring activi ty which had adversely impacted their health and the surroundings. This situation had regrettably resulted in hostile protests by the affected villagers which could be a threat PCIHBV operations. A technical assessment was conducted to devise a safer, secure and environmentally friendly approach to replace the conventional flaring method. At the same time, PCIHBV also envisioned to minimize the duration required from flaring activities. A new approach called "Zero Flaring" was introduced. The concept of Zero Flaring is meant to treat and neutralize the recovered crude during well clean up and divert the flow towards oil processing facilities. This will then rule out the need to burn the recovered crude in the flare pit. To implement the ‘Zero Flaring" only a minimal site modifications were required with few additional equipment such as chemical injection skid, tanks, sampling points and associated connection. This method has totally eliminated the need for flaring while safeguarding the asset integrity of the processing facilities. This innovative approach has been acknowledged by the Host Authority as it has resolved the flaring issues with minimal expenditures required. As of March 2019, PCIHBV has conducted new wells unloading using "Zero Flaring" method in more than 10 wells. PCIHBV is committed to further improve the ‘Zero Flaring’ method to reap its benefits. This new method has showcased PCIHBV's commitment, values and capabilities as a prudent Operator to safely and timely deliver the production targets without neglecting the social wellbeing of the surrounding communities, the protection of the environment and the integrity of the asset. Above all, it has strengthened PCIHBV's presence in this region and further enhanced our reputation as an International Oil Company (IOC) of choice.

Up until recently, the monitoring of greenhouse gases with satellites had been limited to a regional or global scale. Because of the low spatial resolution of scientific satellites looking at gases, attributing emissions to specific facilities had so far not been possible. GHGSat changed that narrative with its first satellite GHGSat-D in June 2016, the first and only in the world specifically designed to monitor emissions directly from industrial sites, with a spatial resolution of less than 50m. The system makes it possible for oil and gas companies to keep a frequent eye on their facilities scattered across vast areas at the lowest cost possible since all measurements are performed remotely with no need to access the sites. We present recent single pass measurements taken with our demonstration satellite in the Short-Wave Infrared (SWIR) band, showing evidence of point source emission plumes at facilities such as underground coal mine vents and oil and gas facilities. The lessons learned from GHGSat-D in the last three years making over 4,000 measurements at hundreds of facilities around the world have been incorporated into our second satellite scheduled for launch in August 2019. As a result, GHGSat-C1 is expected to improve on the performance of its predecessor by an order of magnitude. We will present some of the first results from this second satellite. Finally, we introduce some of the innovative products and applications we are developing using analytics, artificial intelligence and machine learning to better serve our customers with actionable insight and optimize the operation of our system. The ability of the technology to work together with other sources of data (such as other satellites, drones or ground measurements) in an effective tiered monitoring system will also be demonstrated.

A reliable flare system is an important part of most oil and gas facilities. In an emergency or similar process shutdown event where pressure relief is required, the flare system must safely and reliably handle and dispose of waste gas through burning it to atmosphere. However, outside of these emergency cases, many facilities also carry out continuous or routine flaring, where purge gas, waste gas and other low-pressure gasses are sent to flare to be burned to atmosphere. As the environmental and subsequent legislative pressures have increased over recent years, Operators are actively looking for low cost, reliable Flare Gas Recovery (FGR) solutions. This involves recovering flare gas and diverting it away from the flare system to an alternative destination, thereby avoiding the need to burn the gas to atmosphere. Most commonly, recovered flare gas can be used as fuel gas or returned to production, providing some commercial value to the Operator. As most flare systems operate at low pressures (close to atmospheric pressure), gas compression is required to increase the gas pressure to allow the recovered flare gas to be used as a fuel gas or returned to production. Traditionally, rotating-type compression equipment has been employed to compress low pressure flare gas including Liquid-ring, Screw, Sliding Vane or Reciprocating-type compressors. However, due to their reliance upon moving parts in direct contact with flare gas, rotating equipment is prone to break-down. For many facilities with an FGR system, one of the most common causes of unplanned flaring is due to the breaking-down or ‘tripping’ of FGR compression equipment, counter to its very purpose to reduce flaring. These compression devices are also adversely affected by the flare gas stream, which is often poor quality. As an example, high levels of hydrogen sulphide (H2S) is a very common characteristic for flare gas streams. This ‘sour’ gas is one of the primary causes of degradation of compression equipment. In particular, this affects the equipment seals and sealing arrangements. This paper explores how Ejector technology (sometimes known as Eductors, Jet Compressors or Surface Jet Pumps) can be used as an alternative to rotating-type compression equipment for FGR and how the unique challenges of this duty are overcome.

Increasing trends in the digitalization of gas turbine plants allow significant opportunity for utilizing predictive maintenance methods to optimize engine performance. Digital twins have been used extensively to detect anomalies, prevent failures and encourage preventive maintenance activities. An active area of research is how to shift from preventative maintenance based on current conditions, to predictive maintenance based on future conditions. Close mapping of historical engine performance against air quality metrics and ambient weather conditions allow significant progress to be made towards true predictive maintenance, by providing a greater understanding of the condition of the turbine air inlet and compressor section. This allows for increasingly accurate predictions of future engine degradation due to air inlet pressure drop and compressor degradation to a fidelity useful for scheduling maintenance needs. An economic optimization can then be performed balancing the costs of the two engine degradation modes and the corrective actions that can be taken, namely air inlet pressure drop against filter replacement interval, and compressor degradation against compressor soak wash interval. This paper describes our experience in monitoring turbine performance to predict and optimize maintenance needs in combined cycle power plants.