Mitigating greenhouse gas emissions and meeting the aim of the Paris Agreement requires worldwide action from all sectors of society. As a major emitter of energy-related CO2, the transport sector will require a transformation over the course of this century. Before, during and after the adoption of the Paris Agreement, IPIECA issued a series of publications, held dedicated workshops and hosted a number of topic-specific side events at UNFCCC COPs (Conference of Parties) to convene experts from industry, academia, think tanks and other stakeholders to produce a perspective on the potential pathways toward a low-emission future and the role of the oil and gas sector as an enabler. Building on this approach, IPIECA worked with experts within the sector and drawing upon data and literature from the IEA and other bodies to produce in-depth low-emission pathways for transport. IPIECA identified a wide range of technologies that will be necessary for transport sub-sectors (light-duty and heavy-duty road vehicles, aviation and maritime) to evolve to a low-emissions future. Continuing improvements in the efficiency of the internal combustion engines coupled with hybridization and optimized vehicle/vessel designs will provide significant GHG emission reductions. Electric vehicles are key for the light-duty sector, although the full life cycle of battery manufacture, utilization and disposal as well the sustainability of electricity generation source is particularly important if valid comparisons are to be made with internal combustion engines. More advanced biofuels, synthetic fuels, ‘e-fuels’ and hydrogen could also be used as a power source to improve emissions. And, there is a role for carbon capture and storage (CCS) in the production of hydrogen. Transport modes such as heavy-duty vehicles, aviation and commercial shipping need a significantly high energy density. Here electrification will present more of a challenge and there is the opportunity for use of sustainably sourced biomass as an alternative. This paper will lay out the IPIECA view on how the oil and gas industry can be part of the solution in meeting both the challenges of the Paris Agreement and the UN Sustainable Development Goals. It examines in detail potential pathways for the transformation of the transport sector and provides a perspective on the technologies and other key enablers of a low-emissions transport future.

The objective of this paper is to share our lessons learned from 10 years of carbon emission reduction efforts and reporting. This includes emissions from our direct operations and value chain and more recent efforts to measure, reduce, and verify emissions from our products and services. We provide a holistic view of our journey, including successes and challenges. Our data collection efforts have evolved over the years as we’ve endeavored to obtain verifiable information across a complex global organization. We’ll describe how to select a scope and boundary, develop a reporting threshold, present data to improve visibility and drive behaviors, enhance reporting processes, obtain desired precision and accuracy, and ensure appropriate external verification. We also discuss considerations involved with external reporting through company reports, to CDP 1 , and to investor sustainability surveys. Finally, we review how to identify improvement projects, establish the business case, examine funding mechanisms, organize an internal strategy team and leverage internal and external collaboration forums. We’ll demonstrate how our 10-year track record of consistent progress enabled our bold commitment, to reduce our combined Scope 1 and 2 carbon equivalent emissions 50% by 2030 and to achieve net-zero by 2050. Our carbon reduction pathways include: Facility Operational Improvements Identifying opportunities using energy treasure hunts, audits, and Lean Six Sigma/kaizen events, installing smart meters, variable frequency drives, automation, additive and intelligent manufacturing, and lower emission refrigerants. Building Construction, Renovation, and Retrofits Using sustainable building standards and energy efficient equipment including LED lighting, building automation systems, heating/cooling equipment and building envelope. Transportation in Company Vehicles Implementing a vehicle idling policy, optimizing scheduling and logistics, and enabling use of electric vehicles. Renewable Energy Sourcing Incorporating an increased percentage of renewables in utility contracts and the increased use of onsite power generation through rooftop solar and other opportunities. Tool and Equipment Redesign Reducing energy consumption as identified by the systematic use of life cycle assessment to quantify emissions of our products and services. In addition to tool and equipment redesign, we are working to reduce other elements of our Scope 3 emissions through employee commuting solutions and evaluating and adjusting modes of transport through the Eco Mode process. We believe the continuity of experience across a full ten-year period provides a broad array of learnings, which can help others at various stages of their journey. As of mid-June 2019, we were the first and only energy service and equipment company to have made a carbon reduction commitment that aligns with the Paris Climate Accord, demonstrating that we will do our part to limit global warming to 1.5 degrees Celsius.

Greenhouse gas (GHG) emissions contribute to climate change and can negatively affect the reputation of petroleum companies, being a challenge for their operation. This study evaluates three options for reducing GHG emissions in the Llanito field, located in Santander, Colombia. The first is based on curbing gas flaring, by building natural gas pipelines and promoting the use of the gas. The second considers the installation of a steam recovery unit in a flash tank. The third comprises the CO 2 capture and subsequent injection in the hydrocarbon reservoir (CCS), aiming at enhancing oil recovery (EOR). Findings show that, in the first case, emission decreased from 21.05 gCO 2 /bbl to 16.71 gCO 2 /bbl. The second case lowered emission intensity by 3.24 gCO 2 /bbl, and in the third case, emission intensity decreased from 25.01 gCO 2 /bbl to 17.58 gCO 2 /bbl. The implementation of the three cases together (case I + case II + case II) has a potential to reduce the emission intensity by 19.01 gCO 2 /bbl.

The International Association of Oil and Gas Producers (IOGP) has collected environmental data from its member companies every year since 1999. The objective of this programme has been to allow member companies to compare their performance with other companies in the section, with the aim to lead to improvement and more efficient performance. It also contributes to the industry's wish to be more transparent about its operations ( IOGP, 2017 ). There is growing attention to methane emissions from the oil and gas industry supply chain. Natural gas operations contribute to global anthropogenic methane emissions and if not properly managed may undermine the widely recognized environmental benefit of gas utilization. Nevertherless, statistics for methane emissions, particularly from O&G sector, are widely variable. This is not only a risk for climate change mitigation, but also financial and regulatory risk for both investors and operators.

Policymakers and stakeholders target methane as a significant contributor of global warming and so expectations to better understand and reduce methane emissions are increasing among the oil and gas industry and other sectors. This paper will present the findings of research conducted by a taskforce of members of an international petroleum industry environment conservation association and content of the resultant ‘Methane glossary’, which provides additional information on key methane-related terms to enable the use of a consistent and clear terminology within the methane discourse. From 2013 to 2017 this association undertook a range of activities on methane including, holding a workshop and publishing a report on short-lived climate forcers, and publishing a fact sheet on ’Exploring methane emissions’. It also held a workshop to discuss gaps in knowledge on methane and consider studies, data and measurements from a variety of oil and gas operations globally. As a result, the ‘Methane glossary’ will present information to enhance industry understanding of methane management and emission sources. The Glossary is a result of extensive collobaration between the industry association technical specialists, over many months, looking to utilise existing, clear defintions wherever suitable, adding clarity and consistency to other terms and complementing that with additional context to support the reader where that is helpful. The Glossary provides technical information for each of the terms selected, which range from concise wordings in some cases and more detailed text with pertinent, additional contextual information included, to provide a clear and consistent understanding of the terms described. The additional information has been extracted from a selection of academic papers, industry experience and publicly available good practice documentation. The format of the Glossary was designed to take the reader through a logical flow of information, and is therefore divided into seven key sections: (1) Introduction, which provides contextual information on methane as well as instructions and clarifications to lead users throughout the document; (2) Methane sources, which outlines what the methane sources are, where to find them and why they occur; (3) Emissions estimation methodologies, detailing some of the main methodologies used to estimate methane emissions and related terms; (4) Methane detection and measurement which presents a list of work practices and technologies that can be used to measure methane emissions quantitatively and qualitatively; (5) General terms; (6) List of acronyms; (7) Proposals for further readings.

This paper describes how a carbon management strategy for Kuwait Oil Company (KOC) was developed, building on the GCC award winning Air Compliance Management Program. A range of measures to reduce greenhouse gas emissions were assessed technically and economically, including measures that could be implemented by KOC or more widely across other sectors in Kuwait. The potential contribution that carbon capture and storage could make, including with enhanced oil recovery, was also assessed. The results are presented in terms of an abatement cost curve for reducing GHG emissions in Kuwait which is comparable to abatement cost curves collated for other countries. Kuwait has the potential to reduce GHG emissions to 29% below 2030 levels at zero net cost, i.e. the cost of investment to deploy emission reduction measures would be offset by direct cost savings in energy and water. Applying the same ‘zero net cost’ to KOC suggests its own GHG emissions could be reduced to 15 – 20% below 2015 levels by 2030. This could include implementing measures within the local community; initiating actions that could be adopted more widely across Kuwait. The ‘zero net cost’ proposition strongly supports implementation of measure to reduce GHG emissions in the short term and would provide a strong basis for investment in other measures, such as carbon capture and storage, in the longer term.

As a drilling contractor when NDC opted to put in place an Energy Management system it became imperative to establish a baseline of energy consumption so that improvement of energy practices could be measured against this baseline. The task was entrusted to DNVGL Noble Denton. But this posed a unique challenge because very little work had been previously done in the field of energy management by drilling contractors across the world. Due to this ready reference material was not on hand that could be adapted to achieve the baseline study. This paper explains the process adopted by both companies and the outcome of the effort. The task was approached by first preparing an inventory of the energy consumers across the company. Because the company owned assets stretching across Onshore and Offshore, real estate and transport vehicles, the assets were first grouped into various types. These were: Onshore Rigs Offshore Rigs Centralized crew camps Head Office Buildings Warehouse Workshops, and Transportation assets Then a sample of each type of asset was visited and the main energy consumers identified. The energy consumption patterns of these assets was then examined to arrive at a specific consumption value that could serve as a baseline for continuous improvement. The challenges of identifying a typical energy demand for drilling rigs arose from the fact that the energy demand was greatly influenced by the vagaries of the drilling program, type of well, operational practices etc. Overcoming these challenges required that assumptions be made to rationalize the data so that it could be applied across the company assets. The baseline energy audit was successfully concluded and areas for improvement were meaningfully identified. This was the first time that a baseline energy audit for a drilling contractor had been prepared and it has paved the way for other drilling contractors to benefit from the effort. Not surprisingly the audit revealed that the major consumers were the rig engines and thus the maximum benefit could be realized from focusing the company energies on managing these engines. Naturally other easier to implement options exist and have been identified for improving the energy consumption This is the first effort at establishing an energy consumption pattern for a drilling company in the region and is likely to become a trend very soon because the adoption of the recommendations can be easily and quickly translated into savings for the company running into millions of dollars.

The reduction of greenhouse gas emission in oil and gas production could bring several benefits including energy conservation, cost reduction and economic returns. The direct emission measurements and reduction potential evaluation is the prerequisite to achieve an effective reduction goal on greenhouse gas emission. Based on the survey of production processes and related parameters, a series of greenhouse gas emission sources were identified and measured. The emission sources including production processes, leakage-prone facilities such as dehydrator, boilers, heaters, associated gas treatment plant, light hydrocarbon recovery unit, storage tank, and gas flaring were measured. A series of leakage detection and measurement instruments were applied as well, such as Hi-Flow™ Sampler, impeller flowmeter, Bascom-Turner gas sentry and gas flow probes, etc. Based on the measured emission data, a simulation model was then used to evaluate the specific forms, sources and the reduction potentials of the greenhouse gases. The measured greenhouse gas emissions showed that: evaporation and flashing losses from storage tanks were the largest source, accounting for 86% of the total methane emission, and 42% of the total greenhouse gas emissions. The contribution of methane emissions from heaters and boilers during incomplete combustions was less than 1% of the total methane emissions, and about 16% of the total greenhouse gas emissions. When controlling technology on storage tank losses was applied, methane emission could be reduced by 81.7%, and the greenhouse gas emissions could be reduced by 39.9%. Furthermore, such controlling technologies also presented substantial economic benefits through the recovery of fuel gas. In this study, the recovery potential of various greenhouse gas emission sources were analyzed. In addition, a preliminary cost-benefit analysis was performed per the emission categories, reduction potentials, and the feasibility of reduction technologies. Finally, the probability on the application of such reduction technologies were evaluated.

An oilfield services company has completed a pilot program on a global scale that recognizes the value of energy reduction in terms of sustainability and environmental performance. This paper describes the program that ran for a year with tangible targets for energy reduction, with a focused and structured approach. The program resulted in demonstrable reductions in energy consumption for a proportion of the facilities involved and resulted in valuable insights for future programs. The program, named Mission Emission was piloted on a global scale amongst specific locations belonging to the company’s engineering and manufacturing group. The three key deliverables for the 34 locations in 13 different countries were detailed carbon emissions data collection, an energy survey (including key plant and equipment at each facility) and implementation of identified improvements. The results of the program were evaluated by further data collection at the end of the year. The program resulted in an overall reduction in carbon footprint of 17% and significant financial savings. The program highlighted the critical importance of management support, the need for fundamental knowledge of facilities maintenance and energy management, and the challenge in selecting an appropriate metric to suit multi-country locations with wide variations in population, facilities infrastructure and business activities. 14 locations managed to achieve an energy reduction based on 2016 vs 2015 CO2 e kg per man hour, and 9 of these made the target of 5% reduction. The program saw that even the simplest of changes made an impact, including focused management of high energy consuming manufacturing equipment and machinery, switch off campaigns, strict control on lighting, heating ventilation and air conditioning. The successes of the program have been communicated internally and externally as part of the company’s sustainability reporting. The initiative has provided valuable insights on how future programs may be structured, helped to positively engage employees, and has offered a best practice example for other groups within the company. With concerted focus and management support, reductions in energy consumption and associated cost savings can be made without significant financial investment.

Norway is the third largest gas exporter in the world and the second largest exporter of piped-gas to Europe. Natural gas, mostly consisting of methane, has a low CO 2 emission per unit of energy produced during combustion compared to other fossil fuels. However, methane itself is a powerful greenhouse gas and a high level of methane emissions along the value chain could potentially offset the climate benefits of natural gas in a comparison with more CO 2 -intensive fossil fuels. With this background in mind, the present study examines greenhouse gas emissions along the Norwegian pipedgas value chain. The study boundaries extend from production on the Norwegian Continental Shelf to end-user delivery on the British and German gas markets. Primary emissions data are used for production and processing (the upstream and midstream sectors), while results from recent international studies are used for transmission and distribution (the downstream sector). The aggregated results are presented in the perspective of a coal vs. natural gas comparison. The emissions attached to Norwegian gas are also benchmarked in the European context. The greenhouse gas intensity associated with Norwegian gas delivered to customers in the United Kingdom and Germany appears to be significantly lower than the corresponding average for all gas consumed in Europe. Methane represents just 4% of the total GHG emissions. For the gas value chain from the Norwegian Continental Shelf to end-users in the United Kingdom and Germany, over 90 % of methane emissions occur in the transmission and distribution sectors. Considering the gas value chain from production to gate-delivery to customers in the United Kingdom and Germany, the methane emissions associated with Norwegian gas are below 0.3%, while the average for all gas consumed in Europe is 0.6%. These performances are related to the quality of the Norwegian subsea transport network, a high CO 2 tax, focus on minimizing methane leakage due to safety risk and a close cooperation between the gas producers and the Norwegian authorities with regard to methodological developments. Overall, the estimated levels of methane emissions support the climate benefits of natural gas compared to coal, both for the Norwegian gas and for the average of all gas consumed in Europe.

Emissions from energy use are the oil and gas industry's largest direct GHG source. Simple, top-down metrics (eg energy per barrel) do not account for the inherent differences between asset types (eg LNG, pipelines) and are insufficient to identify specific improvement opportunities. Drawing on our downstream experience, BP has developed a modular, bottom-up energy benchmarking approach for upstream. This focuses on energy performance, distinguishing it from underlying, inherent energy use. The energy benchmark for each facility is the sum of individual processing ‘modules’ appropriate to that facility - eg gas compression, liquids pumping, etc. Each module's benchmark is based on its fluid throughput, together with key factors that determine energy demand - eg inlet and outlet pressures, equipment efficiencies, etc. The total benchmark energy for the facility is compared to the energy it actually uses to determine its Energy Performance Index (EPI), so a facility that uses no more energy than its benchmark has an EPI of 100, whilst one using twice the benchmark has an EPI of 200, etc. All BP's operated upstream facilities have been energy benchmarked using this methodology and there was a range of outcomes. The reasons for this are multiple: age, design, complexity, current throughput, as well as other operational factors, and further analysis is required to understand individual facility results better. Facilities also differ considerably in energy use: from 15 MWth for a pipeline, to more than 1,000 MWth for a Gas Liquefaction (LNG) plant. Facility size and EPI together establish the facility's ‘energy opportunity gap’; that is, the gap between actual and benchmark energy. This energy performance opportunity data has been used to prioritize where to focus supplementary, deep-dive energy reviews with the aim of identifying economic energy performance improvement opportunities. Additionally, full energy gap analysis should help identify and quantify common opportunity themes and potential technology gaps across our upstream portfolio (eg waste heat). Given the challenges to implementing the more fundamental opportunities to existing operating facilities, especially offshore, the most significant findings are more applicable to future operations (ie major projects currently in development). Hence, as part of our forward GHG plans, energy benchmarking is to be applied to future major upstream projects. The approach applies maximum energy supply efficiency curves based on facility heat-to-power energy demand ratios. Minimal data input required is collected via simple spreadsheet (only for modules applicable to that facility). This modular benchmarking approach can be readily expanded to include other GHG emission sources: eg flaring (based on flaring categorization: eg routine, non-routine, safety-related), and methane (based on methane sources: eg flaring, pneumatics, fugitives, vents, etc.), and thus in combination achieve overall facility GHG benchmarking.

Meeting the challenge of climate change requires worldwide action from all sectors of society. Throughout this transition, oil and gas will have a role to play within the mix of energy sources to meet the need for affordable and clean energy products and services. IPIECA has identified a list of common elements and enablers of future pathways that most projected low-emissions pathways shared. The resulting paper considers the near- and long-term aims of the Paris Agreement, along with the challenges to address climate change whilst meeting the UN Sustainable Development Goals. Further to this, the current energy system is explored in order to provide a basis to evaluate the common elements of the multiple pathways to a low-emissions future. The three common elements of an energy system transition are: improving efficiency; reducing emissions from the power generation; and deploying alternative low-emission options in end-use sectors. The common enablers of a low-emissions pathways identified are: collaboration, effective policy and the availability of finance. This paper explores in detail these elements and examines key technologies to support this transition. The role of the oil and gas industry in meeting the long-terms aims of the Paris Agreement is also outlined. Furthermore, it addresses the challenges on addressing climate change in the context of the Paris Agreement and the UN Sustainable Development Goals and provides a perspective on the role of the oil and gas industry as enablers of pathways to meet a low-emissions future.

Objectives/Scope Stakeholder and government expectations on transparency and disclosure are steadily growing. Specifically for greenhouse gas emissions, there are greater pressures to move beyond reporting direct corporate emissions and indirect emissions from energy use, to disclosing other indirect emissions (" Scope 3" ) deemed to be material. These emissions are from sources such as capital goods, business travel, franchises and use of sold products. In 2011 WRI/WBCSD released the GHG Protocol Corporate Value Chain (Scope 3) Accounting and Reporting standard to help companies identify, estimate and report these emissions. Methods, Procedures, Process In 2014, IPIECA, in collaboration with API, began work with consultant Environ (now Ramboll Environ) to support companies on the topic through two activities. Firstly, by identifying sources of scope 3 emissions in the oil and gas industry, as well as evaluating their materiality, and secondly, by detailing the different estimation approaches for those wishing to report them. Results, Observations, Conclusions, In establishing the boundaries of a scope 3 inventory, companies must first determine which activities are material. Materiality determinations should be based on both qualitative criteria (such as influence, risk, stakeholders, outsourcing and sector guidance) and quantitative consideration in order to meet the needs of inventory users, including both reporting companies and external stakeholders. We examine the 15 categories of scope 3 emissions as defined by the 2011 WRI/WBCSD GHG Protocol Corporate Value Chain guidance, and provide detailed guidance on those categories deemed to be material, as well as summary guidance for those categories less likely to be material. Of the 15 scope 3 categories, two are likely to be most material. Use of sold products (Category 11) is the dominant category for companies in the fuels value chain. For petrochemical companies a number of categories appear likely to be material, particularly purchased goods and services (Category 1). IPIECA have since been considering approaches to corporate value chain accounting ( Scope 3 ), intending to identify credible, consistent, and reliable scope 3 GHG accounting and reporting practices from oil and gas companies. This paper outlines some of the materiality, boundary, and methodological considerations relevant to emissions sources for the petroleum industry. It includes accounting and reporting principles, and criteria and guidance for identifying materiality. Novel, Additive information In addressing boundary issues, we describe different tactics for reporting depending on where in the value chain a business operates. In addition it explores how to address the materiality of category 11 Use of Sold Products and the issue unique to the fuels industry of how to consider the duplication of category 11 emissons in other categories.

This paper presents how an Oil and Gas Company (Total) has adapted their environmental reporting to implement their commitment to the UNEP CCAC OGMP (OGMP). The Company joined the OGMP, which focuses on measurement and control of methane emissions from the Oil & Gas industry, in November 2014. This paper also explains the importance of having accurate data on methane emissions in the light of methane high Global Warming Potential (GWP). The OGMP methane reporting implementation is a new challenge for the Oil & Gas industry. The Oil & Gas industry is allegedly the second largest methane emitter after agriculture. OGMP defined nine core methane sources identified all along the Oil & Gas production process and a new reporting system emphasizing on the methane footprint of the Companies’ activities. In this paper, the adaptations provided to Total's environmental reporting are explained step by step in order to illustrate the specifics linked to the participation in the OGMP. Methods and equations are also provided for each potential source. The involvement in the partnership allows improving methane emissions reporting and adopting the uniformized reporting methodology of the OGMP for each participating Oil & Gas company. The work done to take into account the new nine core sources is an essential point of the partnership. This work requires the understanding of the new sources and the identification of those within the Company reporting system. Once this step is done, the reporting is simple and allows assessing the methane emissions covered by the OGMP's reporting system. Thus, the Company can estimate their methane footprint and set up mitigation options toward the methane sources identified. In addition, an aggregated annual report is done with purpose communicating the work done by the Oil & Gas Companies on methane emissions reductions. The OGMP is an open forum with Governments and NGOs members, thus not only limited to Oil & Gas Companies for sharing technical information and consequently, not seen as an Oil & Gas lobby by the public. It is able to fund technical studies thanks to its own budget. Participating to OGMP is a Company internal motivation factor for improving methane reporting and emissions reduction. An additional benefit of participating to the OGMP is getting feedback and technical expertise to manage and reduce methane emissions in a standardized scheme and under the umbrella of an internationally recognized institution. This paper can be seen as a guideline for Oil & Gas companies to put in place a methane emissions reporting in line with the OGMP. It describes also the benefits and drawbacks of joining the OGMP.

The opportunity to influence a project design in terms of added value and competitiveness is most significant at the very early stages of design, when concept options are being identified, screened and selected. This is recognised in BP and a Global Concept Development (GCD) organization has been created as a centre of expertise in its upstream segment to deliver safe, cost effective and competitive major project concepts. The GCD integrated team is a multi–discipline team including resources allowing consideration of environmental and social factors, such as regulatory compliance but also striving towards environmental and social improvement. The ability to influence design through the Environmental and Social (E&S) lens enables: Concept E&S differentiators or showstoppers to be identified and evaluated as part of the concept selection process; Opportunities for the assessment of E&S value improvement; and Added value gained during concept development in the management of E&S risks leading to safe and reliable operations and a smoother transition into optimize - the next stage of BP's Capital Value Process (CVP). This paper explains the environmental and social mechanisms that are applied in GCD, which form part of the GCD integrated approach. The opportunity to challenge new projects to be innovative in the use of industry standards and new technology can make a significant contribution to enhancing value and managing risk. This includes working with other disciplines to develop their awareness and application of environmental and social issues in new projects, such as energy efficiency, water usage and water discharge. Areas of focus for this paper are: the concept of inherent environmentally robust design (IERD) - an innovative approach applied to assessing projects during concept development, which strives toward achieving continuous environmental and social performance improvement; the integration of energy efficiency benchmarking; and the identification of environmental sensitivities early on to inform development planning. Lessons learned from BP's existing operations and their incorporation in new projects are also discussed. The benefit of continuously feeding back lessons learned from BP's operating assets into new project designs ensures that the environmental performance of major new projects matches expectations of the region it will be operating in and also of the company.

In the UK, there is significant focus on external certification organizations to verify management system standards of companies operating in the country. For example, in the oil and gas industry, there are external certification requirements for the subject matter areas of quality; health, safety, and the environment (HSE); and sustainable development. The challenge lies not in meeting the requirements of external certification standards but rather in approaching the process as a whole instead of by separate subject matter areas. To address this challenge, an oilfield services company with operations in the UK developed an integrated management system for all subject matter areas. The company integrated the subject matter areas into a single approach and derived benefits from this streamlined initiative. The company, which has had long-standing, robust management systems for quality, HSE, and sustainable development, integrated these subjects into one management system instead of considering each subject within its own individual system. The initiative involved designing the process and procedures, implementing the system into operational planning, and developing certain key features such as customized dashboards for line managers to track outcomes. After a year of implementation, the integrated management system has provided significant benefits in strategic risk-based planning as well as continuous improvement. Metrics are monitored using a dashboard approach to provide management with an immediate overview of performance, which not only raises awareness but also increases focus on key indicators in decision making and planning. The integration process has also resulted in a significant streamlining of the management system structure and documentation. This integrated approach has led to ongoing performance improvements throughout the procurement and operational lifecycle management.

The Goliat field operated by Eni Norge AS, with Statoil Petroleum AS as the only partner, will be the first offshore oil field in the Norwegian Barents Sea and the world's northernmost offshore oil field. The Goliat field is being developed with a geostationary FPSO connected to 8 subsea templates with 22 wells (12 production wells, 7 water injectors and 3 gas injectors). The FPSO is on location and commissioning work is ongoing. The field is located in the south western part of the Barents Sea, relatively close to the coastline. The Barents Sea is a sea area important for a number of fish stocks, sea birds and sea mammals. A number of "Particularly valuable and vulnerable areas" has been identified as part of the work conducted in relation to the update of the "Integrated Management Plan for the Marine Environment of the Barents Sea–Lofoten Area" presented to the Norwegian Parliament in the "White Paper no. 10 (2010–2011). The area has high political focus, especially on oil spill preparedness and environmental issues. Environmental issues have been highly prioritized through all the project phases, in order to fulfill the frame work conditions set for the sea area by Norwegian Authorities and the specific requirements set by the Norwegian Parliament when approving the Plan for Development and Operation (PDO) for the Goliat field in 2009. The Goliat development project has developed and implemented new solutions, which will result in improved environmental performance. The paper will address how the Goliat development project has implemented environmental BAT (Best Available Technic) solutions in relation to: Power solution (electrical power from shore in combination with gas turbine on FPSO) Emission to air reduction measures (mininimize GHG (Green House Gases) and other emissions, improved energy efficiency) Reduction of discharge to sea (re-injection of produced water, slop tank size, internal drain system, facility design) Offloading solution (new design) Environment monitoring solution (leak detection) Oil spill preparedness (new concepts in coastal areas) The paper is closely linked to previous SPE papers presenting the Goliat field development, such as SPE paper 156773 "Implementation of the oil spill preparedness for the Goliat offshore oil field development – The first oil field development in the Barents Sea" ( 1 ), SPE paper 156795 "Coastal Oil Spill Preparedness Improvement Programme (COSPIP) and Memorandum of Understanding – Comprehensive Joint & Industrial project focusing on coastal oil spill challenges" ( 2 ) and SPE paper 126598 "EIA for the Goliat Offshore Oil Field Development. World's northernmost offshore oil development?"( 3 ).

The recent rapid expansion of natural gas developments and utilization worldwide are bringing into focus the need to improve understanding and characterization of greenhouse gas emission sources, including methane, associated with petroleum and natural gas systems. New production technologies and practices, including those involving hydraulic fracturing, necessitate a thorough review of existing quantification methods for fugitive methane emissions from venting, flaring, and equipment leaks associated with petroleum and natural gas systems and operations. In the past few years widely divergent estimates have emerged regarding methane emissions from the U.S. natural gas industry sector. Some discrepancies noted by industry surveys have led to a thorough review of newly available information and are leading to the improvement of estimation methods and emission factors associated with activities that comprise natural gas systems. This has manifested itself in the engineering estimations that are used for compiling the national U. S. GHG Emissions Inventory and in the methods used by companies for reporting under the U.S. Environmental Protection Agency mandatory Greenhouse Gas Reporting Program. This paper will present results of a comparative analysis of GHG emissions data, including methane, for key industry segments such as on-shore natural gas production and natural gas processing and their contribution to the so called "petroleum and natural gas systems". The data analyzed will contrast the "top-down" assessments used in developing the U.S. GHG Emissions Inventory with the "bottom-up" estimation of actual emissions as reported under Subpart W of the GHGRP. The analysis will provide a comparison of the estimation methods and evaluation of the contribution of key sources to overall methane emissions. The ultimate goal of this effort is to incorporate the new information that is becoming available into consistent methods that can be used both for national GHG inventory development and for corporate reporting. Harmonization of these methods is expected to contribute to informing the public debate on natural gas use and its role in mitigating overall GHG emissions.

For a responsible O&G company it is no longer acceptable to follow different environmental performance standards that are based on regulatory requirements that vary from country to country. Consequently, beyond strict legal compliance, a set of 150 best environmental practices has been established in an effort to prevent and minimize the environmental impact of E&P operations worldwide. This requirement covers the full range of E&P activities (acquisition, exploration, development, production and abandonment), and it contains specific requirements for key environmental aspects, such as biodiversity, noise, air emissions, wastewater and waste management. A gap analysis was conducted in 15 countries to analyse compliance against the requirement with a global outcome of 11% of cases failing to meet the best practice. This analysis covered all of the activities carried out during normal operations at any worldwide location, onshore and offshore, including joint ventures where the Company was the major shareholder or the operator. The analysis also covered activities carried out on the Company’s behalf by contractors and subcontractors. The study showed remarkable differences in compliance among countries and with regard to lifecycle stages and environmental aspects. For out-of-compliance situations, a tiered-approach was developed for the visualization, conceptualization, definition and execution of actions to meet the requirements. In cases where the best practice could not be met, a new level of accomplishment based on the best available and economically achievable environmental performance must be proposed. A case study of an onshore oil production facility located in a UNESCO Biosphere Reserve illustrates the application of this methodology. The application of this requirement, despite the financial and operational impacts on the company, has proven to be an excellent tool for continuous improvement in environmental management and a solid approach to ensure alignment and harmonization of environmental best practices worldwide.

Constrained access to oil and gas reserves is one of the top risks for future oil and gas. The best energy opportunities are in frontier areas and in new unconventional resources, but these often overlap with environmentally sensitive or refuge areas.Advances in technology have brought these high risk areas within business radar of companies, but have catapulted new environmental risk dimensions (potential "show stoppers") to the forefront of corporate opportunity ranking. A comparison will be made of pioneering approaches to deal with cumulative risk in offshore polar zones and new onshore unconventional energy. In new frontier Arctic areas, increasing levels of cumulative noise pollution can disrupt the ecological sounds cape of marine species upon which they depend for their survival. In contrast, advances in fracking technology onshore have brought into stakeholder focus the widespread and cumulative risks of unconventional energy both in terms of surface multiple drill site infrastructure and subsurface invisible cumulative risks to critical subsurface water resources. A critique of new techniques, current research and innovations into the development a 3D risk-scape for the marine environment to assess the significance of human imposed sound pollution on former pristine bioacoustic habitat, will be presented. Unlocking access to these energy resources will require industry to demonstrate how marine species and unique habitats can be safeguarded from mu cumulative threats over the next 20 years. Cutting edge approaches to lifecycle evaluation of unconventional energy development using GIS data bases and mapping to measure and communicate overall impact to stakeholders, will be illustrated using case selected case histories. Insights will be given into subsurface modelling and monitoring techniques to reduce long term risk to critical water resources. The first stage of unlocking access to sensitive reserves is to achieve "preferred bidder" status for new acreage, which will be judged on corporate delivery of environmental and safety performance past promises made around the globe. Industry needs to convince stakeholders, that cumulative environmental risks in escalating development can be managed using new innovative techniques to safeguard the sustainability of key species, or face lockout of some vital areas.