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.

To mitigate climate change, the execution of large-scale projects is necessary. The 20-year projected scenarios show that all actions that are technically viable are required, including some that have to be executed with significant financial assistance from the Government. Global warming generated by the increase in Greenhouse Gases (GHG) is one of the most serious environmental, social and economic threats currently facing the planet, therefore it is essential that each individual, organization or country, is involved in a broader conversation about the importance of planning and taking a strategic approach to combat it. This research, accompanied by analytical work, allowed documenting one of the possibilities of capturing GHG, which could be synergized with an important project such as the development of Colombia's source rock hydrocarbon resources. An economically viable option that can continue its planing stage and be included in the technical options that can be adopted in the future, not only because of the reduction in emissions that it generates, at the same time, the promise of interesting value it can generate a great impact.

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.

The International Association of Oil & Gas Producers (IOGP) has collected environmental data from its member companies on an annual basis for the past 16 years. The programme was set up in response to the industry's wish to be more transparent about its operations and to enable IOGP member companies to compare their performance with that of other companies in the sector. The ultimate aim is to provide a representative statement on the environmental performance in the upstream oil and gas industry. This paper will discuss the analysis of submissions by participating member companies for the years 2013 and 2014. Data were reported by participating companies in the following 6 environmental indicator categories: gaseous emissions; energy consumption; flaring; aqueous discharges; non-aqueous drilling fluids retained on cuttings discharged to sea; and spills of oil and chemicals. The data represent oil and gas wellhead production of 2.1 billion tonnes. Forty three companies took part in 2013 and 2014, operating in more than 80 countries worldwide, and the database now represents what is probably the most comprehensive set of reliable information on cross company performance in the industry. Performance results are presented on a global and regional basis, onshore and offshore, and normalised to hydrocarbon production. Results are shown, for ease of comparison, alongside the previous year's published results.

In 2008, the Norwegian oil and gas industry set a goal to reduce annual CO 2 emissions on the Norwegian Continental Shelf (NCS) by 1 million tonnes by 2020. For Statoil's operations this has meant a reduction of 800 000 tonnes. To reach this goal, Statoil introduced a systematic approach to energy management on all Statoil-operated installations on the Norwegian Continental Shelf (NCS). This approach is based upon ISO 50 001 – Energy Management, and anchored in Statoil's own governing documentation. Relying on a network of energy coordinators, with dedicated roles and responsibilities for energy management initiatives and planning, Statoil has been able to identify and implement measures to meet the original 800 000 tonnes reduction target by the end of 2015, 5 years ahead of schedule. The combination of a well-coordinated and capable network with specific roles, responsibilities, and deliveries, the high price of CO 2 emissions in Norway and significant attention to energy management activities by management have all contributed to the positive reduction results achieved by Statoil on the NCS. Based upon the initial success of this systematized energy management work, Statoil has not only establish a similar energy network for Norwegian, land-based operations, but also set an even more ambitious reduction goal for 2020.

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 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.

The International Association of Oil & Gas Producers (OGP) has collected environmental data from its member companies on an annual basis for the past 14 years. The programme was set up in response to the industry's wish to be more transparent about its operations and to enable OGP member companies to compare their performance with that of other companies in the sector. The ultimate aim is to provide a representative statement on the environmental performance in the upstream oil and gas industry. The data represent oil and gas wellhead production of 2.2 billion tonnes. Over 40 companies took part in 2011 and 2012, operating in more than 75 countries worldwide, and the database now represents what is probably the most comprehensive set of reliable information on cross company performance in the industry. Data were reported in 6 environmental indicator categories: gaseous emissions; energy consumption; flaring; aqueous discharges; discharges of non-aqueous drilling fluids retained on cuttings; and spills of oil and chemicals. Performance results are presented on a global and regional basis, onshore and offshore, and normalised to hydrocarbon production. Results are shown, for ease of comparison, alongside the previous years’ published results. The paper will address the emerging trends in environmental performance as well as factors that underpin the data.

In both the Netherlands and the EU, government policy is directed towards a clean, affordable and reliable energy mix. This goal demands not only energy savings and investments in renewables, but also support of CCS in order to achieve a low carbon footprint in the energy mix. However, public acceptance of onshore CCS in the Netherlands is low; therefore, the government has chosen to support only offshore CCS for the moment. To facilitate the development of offshore CCS, the Dutch government and the European Union are co-funding the ROAD project together with the initiators, E.ON and GDF SUEZ. The ROAD project aims to develop a large-scale, integrated CCS demonstration project. This demonstration project encompasses the capture of 25% of the CO 2 in the flue gases of a coal-fired power plant (owned by E.ON), transporting this through a 25 km pipeline (operated by GDF SUEZ) and storing it via an injection platform in a 3.5 km deep depleted gas reservoir (operated by TAQA). ROAD needs a number of permits and consents to set up the demonstration project. The permitting process is the main process in which stakeholders can participate. By using this permitting process as a case study, and comparing it to a previous (unsuccessful) onshore CCS project in the Netherlands, we argue that it is best to start with a successful offshore CCS demonstration project. Mainly because the NIMBY effect does not play a role, public resistance against such an offshore CCS project is low. The government can then use this project to show that CCS can be done safely and without negatively impacting the environment or the public. In short: a successful offshore CCS project will help establish the necessary societal embedding for future CCS projects in the Netherlands and elsewhere in Europe, both onshore and offshore.

Total is committed to reducing the impact of its activities on the environment, especially its greenhouse gas emissions. The group's priorities are to improve the energy efficiency of its industrial facilities, to reduce the flaring of associated gas, to invest in the development of complementary energy sources (biomass, solar, clean coal) and to participate in many operational and R&D programs on CO 2 capture, transport and geological storage. It has been involved in CO 2 injection and geological storage for over 15 years, in Canada (Weyburn oil field) for EOR and Norway (Sleipner, Snohvit) for aquifer storage. In 20 06, the company decided to invest 60 million euros to experiment CO 2 capture, transportation and injection in a deplet ed gas reservoir. The pilot in the Lacq basin, SW France, 800 km from Paris, has been on stream since January 2010. The experimental plant is unique in several respects; by its size (unprecedented worldwide), capturing carbon through a 30-MWth oxy-combustion gas boiler, by the choice of a depleted deep gas reservoir (unprecedented in Europe) located onshore 5 kilometers south of the agglomeration of Pau (around 140,000 inhabitants) and by its scope, operating a fully integrated industrial chain (comprising extraction, treatment, combustion of natural gas, High-pressure steam production, CO 2 capture, transport and injection) on the SEVESO-classified Lacq industrial complex. The pilot installations were designed by the Total E&P Research and Development team and are operated by Total Exploration Production France. The project reflects Total's commitment to mitigate greenhouse gas emissions. A dedicated plan was devised with the French authorities to monitor the integrity of the injection site and confirm that the CO 2 remains trapped in its host reservoir. Its main objectives are to check that no CO 2 is leaking upward out of the reservoir though either the injection well or the cap rock, so as to avoid any impact on the groundwater and surface water resources, the biosphere (Fauna and Flora) or human health. This paper details the main technical features of the pilot and the monitoring program spanning subsurface and surface aspects, together with the operational feedback after more than two and half years of operation. Based on the pilot's performance to date, Carbon Capture and Sequestration (CCS) appears to hold promise for use on an industrial scale. This industrial operation will capture and trap around 90,000 tonnes of Carbon dioxide over a 3 and half year period. This quantity is equivalent to the exhaust emissions of 30,000 cars over a 2-year period.

As the world moves towards cleaner forms of energy worldwide, gas will have an increasingly important role to play in the future energy mix. From this perspective, there has been growing interest in the relative greenhouse gas (GHG) intensities of a range of fossil fuels, and how various forms of LNG compare to not only coal, but also to renewables and nuclear across their life cycles. These issues are important for energy and GHG policy, especially with developments in carbon pricing. However, until recently there has been little information on the life cycle GHG emissions from Australian fossil fuel exports. This paper helps to complete the picture. Using a wide range of available data from government submissions by industry and the authors’ own project experience, life cycle GHG emissions estimates were developed for LNG derived from conventional natural gas sourced from Western Australia's North West Shelf and Queensland coal seam gas (CSG). A comprehensive assessment of GHG emissions was made for upstream operations, LNG production, transport, regasification, and end-user combustion for electricity generation (assumed to be in China). These life cycle emission estimates were compared to life cycle emissions for Australian black coal exported to China and used to generate electricity. Comparisons were also made with renewables and nuclear. The results show that the life cycle GHG intensity (tCO2-e/MWh) of electricity sent out is highly sensitive to the thermal efficiency of the end-use combustion technology. For most comparison scenarios, natural gas-fired power generation is less GHG intensive than black coal-fired power generation. The differences range from 17% to 56% less intensive for a variety of plant efficiencies. In some cases, coal was marginally less GHG intensive when comparing open-cycle gas technology with ultra-supercritical coal combustion. LNG derived from CSG was also found to be more GHG intensive than conventional gas. Modelling of upstream methane fugitive emission scenarios from CSG (using 100-year and 20-year methane Global Warming Potentials) had little impact on the life cycle GHG intensity rankings, such is the dominance of end-use combustion. When exported to China for electricity production, LNG was found to be 22–36 more GHG intensive than wind and concentrated solar thermal (CST) power and 13–21 times more GHG intensive than nuclear power

Geologic carbon sequestration may involve injection of large quantities of carbon dioxide (CO 2 ) into primarily deep saline aquifers for storage purposes or, where feasible, into oil and gas reservoirs for enhanced oil recovery objectives. The literature and experience from industrial analogs indicates that well-bores (active or inactive/abandoned) may represent the most likely route for leakage of injected CO 2 from the storage reservoirs. Therefore, sound CO 2 injection well design and well integrity, operation and monitoring are of critical importance in such projects. This paper presents design considerations for (1) the construction of CO 2 injection wells including down-hole tubular (casing/tubing/packer) and cements, (2) methods to verify that the wells have mechanical integrity (both internal and external) and monitoring approaches applicable to CO 2 geo-sequestration in the U.S. and a short discussion of the risks posed by abandoned wells within a storage field and the safety aspect of CO 2 wells.

Contextualized overview of the CO 2 EOR and its geologic storage, with critical evaluation of state-of-art and technological development through patents and scientific articles, focusing on annual evolution, technology owners (countries, companies, R&D institutions), inventors, annual evolution of the patents portifolia, field projects, company shared technology, IPC codes, technologic trends and fields, miscible and immiscible processes, capture technologies, relationships between the annual evolution of crude oil production, price, patent deposits and articles published, and technologic maturity of geologic storage. With the high impact on climatic changes, the energy industry is aiming to recover the planet climatic conditions by developing feasible processes. There are a reasonable number of field projects and are several technologic challenges are identified. The annual evolution of patents for CO 2 EOR has the same trend as the other EOR methods, the deposits increase significantly near the petrol crises. The main technology owners are Texaco, Mobil, Chevron and Shell. In indexed articles, BP, Chevron and Shell are the companies that published more and University of Regina (Canada), is the academic leader. Most of the CO 2 EOR field projects are in the US, being US, Canada and Norway pioneers in carbon sequestration. In the Latin America, Petrobras intends to act on all Carbon Capture and Storage chain. The inventors usually act in several technologic fields. Texaco, Mobil, Chevron, ConocoPhillips and Shell invested in alternated injection and surfactants addition. Shell made numeric simulation for miscible and immiscible fluids dislocation. ConocoPhillips studied CO 2 correlations for miscibility pressures. University of Regina studied interfacial tension CO 2 -oil. University of Texas studies foams to change the injection profile. Over 90% of the patents are miscible processes. Patented capture technologies are adsorption, absorption, ionic liquids, and membranes, MOFs, among others. CO 2 − baixar o 2

This paper describes the current studies to define alternatives for the geological storage of the CO 2 present in the associated gas to be produced from the Pre-salt reservoirs of the Santos Basin, Brazil. Recent hydrocarbon discoveries in Santos Basin, offshore Brazil, in the so-called pre-salt reservoirs, brought many challenges for the production development ( Beltrao et al. , 2009 ). The reservoirs are heterogeneous microbialite carbonates, located below up to 2,000 m salt layer thickness, in water depths of 2,200 m. The oil is a 28 – 30°API, with GOR higher than 200 m 3 /m 3 . Besides the unique environment, one additional challenge is the variable CO 2 content in the associated gas. The sustainable hydrocarbon production from the pre-salt reservoirs will, then, require, in line with Petrobras and its partners' vision, avoiding emissions of the CO 2 produced together with the hydrocarbon. The task that would be difficult for onshore oil fields reaches unparalleled complexity in the subsea completion deep water production scenario. Some alternatives are under study for the CO 2 capture and storage: reinjection in the producing reservoirs, in salt caves, in salt water aquifers, in depleted gas reservoirs and even transportation and use of the CO 2 for industrial purposes. Although still in the early stages of development, work done so far paved the way for robust and sustainable gas processing and CO 2 separation, compression and reinjection in secure sub surface geological horizons. The current analysis indicate that the best alternative seems to be the reinjection in the oil producing reservoirs, with a good perspective of enhanced oil recovery by the association of gas and water injection in the Water Alternating Gas (WAG) process.

The climate change agenda is to move from a trend of increasing green house gas (GHG) emissions to either holding emissions flat then reducing over the next few decades. By examining upstream projects early enough in the project lifecycle and using tools to assess energy usage over the field life of the project, reductions in GHG emissions can be achieved, which results in savings of operating costs and future carbon dioxide (CO 2 ) trading costs. Several techniques and tools have been developed which, when applied at the correct stage of the project, can help to optimise energy intensity and CO 2 emissions. These include workshops, forecasting software for GHG emissions and flowsheeting tools to evaluate various design configurations taking into account cost, reliability and project variables such as weight and space. Results show that by applying these tools early in the design life energy intensity can be significantly reduced, which results in lower operating costs for fuel and potential CO 2 costs.

Statoil has forecasted CO 2 emissions from their offshore fields for many years. This paper sums up 8-10 years history of forecasting the emissions from 6 offshore oil and gas fields with 8 producing facilities. The accuracies of the early forecasts for these facilities have been analyzed with focus on the forecasts made in 2001 and 2004. The emission forecasts are made for each producing facility using a field specific forecasting model. These models are calibrated annually by comparing calculated fuel demand with reported consumption. The analysis shows that Proper calibration of the forecasting model over several years improves the model significantly and is necessary in order to keep control of the uncertainties in the forecasts. Through annual calibration of the forecasting model over several years, accurate fuel and emission forecasts within an annual uncertainty level of +/- 4 % is achievable for a short term forecast, provided good production, injection and activity input forecasts. A short term forecast in this context is the next two to five years. Historical data show that the input data (production-, injection- and activity profiles) represent an uncertainty element of the same order and in some cases larger than the uncertainty in well calibrated forecasting models. Future modifications to cope with new and adjusted oil and gas production conditions will add to the uncertainty, in particular for the long term forecast. Operational flexibility will add uncertainty to the forecasts (example gas turbine operation). The uncertainties increases for long term forecasts (< 5 years ahead), due to increased uncertainties in the input profiles as well as in the model itself due to future changes in the production facilities.

The Ormen Lange gas processing facility at Nyhamna in Norway treats gas and condensate produced from the Ormen Lange gas field in the Norwegian Sea. Condensate is exported from the plant via tanker, while gas is exported via subsea pipeline to the UK where it fills 20% of UK natural gas needs. From the start, the intention was to build and operate a plant with minimal impact to the sensitive coastal environment in which it is located. With few exceptions, with respect to discharges and emissions, noise, light, emergency planning, risk management and environmental monitoring, the plant has operated from start-up well within compliance with the very detailed and demanding environmental requirements relative to any comparable facility in a highly regulated industry. Subsea completed wells at a seawater depth of 850m produce to the plant onshore via a 120km pipeline. Slug catchers at the plant reduce the velocity of the flow and begin separation of gas, condensate and water. Further processing includes the reclaiming of mono-ethylene glycol, treatment to meet gas export specification, recompression of the gas to the export pipeline and transfer of the condensate to ships. Concurrent with operations, research and development of new technology to enhance production from the field is carried out at the onshore site. The plant operates without the need for operation of the flare or pilot except under emergency conditions. Process water is treated in a bioreactor to meet strict discharge specifications in a populated, coastal area. Apart from the use of diesel to test emergency fire pumps and electricity from the hydro-electric powered national grid, the majority of the plant's energy needs are provided by heat generated by burning less than 0.5 percent of the incoming gas to the plant. This paper describes the environmental standards governing operation of the Nyhamna plant and the challenges encountered in achieving compliance with these standards. These include technological challenges to measure, monitor and minimize discharges and emissions, studies on possible impacts on the varied marine and terrestrial environments and ongoing efforts to increase energy efficiency of plant operations.

The challenge of balancing energy supplies to meet growing global demands, while concurrently considering associated environmental impacts, is leading to an increased focus on greenhouse gas (GHG) emissions and their potential mitigations. Over the past five years, the American Petroleum Institute (API) and the International Petroleum Industry Environmental Conservation Association (IPIECA) have collaborated on a series of guidelines to promote the credible, consistent, and transparent quantification of GHG emission reductions from projects of interest to the oil and natural gas industry. The Petroleum Industry Guidelines for Greenhouse Gas Emission Reduction Projects (referred to as the Project Guidelines) consists of a series of documents developed to provide oil and natural gas companies with a framework for evaluating, quantifying, documenting, and reporting GHG emission reductions achieved through discreet projects. The Project Guidelines address the selection of appropriate baseline candidates and boundaries for scenario assessment. The documents also address potential emission sources to be incorporated for the selected scenarios, along with compatible monitoring considerations. The guidelines focus on technical considerations and provide flexibility to adapt the approach in accordance with applicable public policy mandates. This paper highlights a recent addition to the series - the Flare Reduction Guidance Document - that addresses GHG emission reductions associated with reduced flaring activities from oil and natural gas operations. Although flaring occurs along the oil and natural gas value chain, the document focuses on exploration and production operations, where the best opportunities for flare reductions reside. Case studies are used to demonstrate the application of the emission reduction principles for two categories of GHG emission reduction projects: (1) recovery of associated gas for processing and sale, and (2) utilizing a small flared gas stream for on-site power generation. Although the concepts for quantifying GHG emission reductions are illustrated through project examples relevant to the oil and natural gas industry, the information is applicable to a variety of project types and establishes the foundation for assessing GHG emission reductions from a myriad of project activities.

Each offshore petroleum production unit has some sources of CO 2 emissions, related to both energetic and non-energetic uses, such as electric energy generation, gas flaring, natural gas and CO 2 ventilating, drainage systems and other meaningless uses. Additionally, some fields may have high CO 2 content present in the chemical composition of the produced natural gas stream. In this case, the separation of the CO 2 stream from the produced natural gas one is mandatory, in order to meet the natural gas specifications established by the regulated bodies. Therefore, this available CO 2 stream can be used in the oil fields in many applications, mainly as a method of enhancing oil recovery (EOR) or even as enhancing gas recovery (EGR). The present paper approaches a methodology of both identification and quantification of each CO 2 and equivalent CO 2 existing source of the petroleum facilities, in such a way of presenting all of them together and also separated though the unit's life cycle.

An oilfield services company has developed and implemented a resource-efficiency trial program using real-time monitoring and reporting of its electricity, gas, and water consumption in some of its United Kingdom (UK) facilities. An external review was commissioned to research and assess ways to provide detailed utility usage data and develop a system to effectively deliver and share these data with multiple users such as facilities managers, environmental managers, and purchasing managers. A smart-metering system was implemented, combining some existing utility meters with newly installed meters at selected sites to provide real-time measurements every 30 minutes. Remote access to the data was enabled through a secure web server, and an intuitive graphical interface provided effective display functionality. The initial target was to review usage over a 24-hour cycle. The trial also indicated the effectiveness of weekly, monthly, and seasonal monitoring. After initial trials were completed, the company was able to identify resource consumption savings, achieving overall substantial cost savings in the process. In some locations, the new system immediately highlighted opportunities for energy-saving actions that easily justified the cost of installing new meters. The simple technology can be easily applied to any office, field support base, data center, or maintenance facility, anywhere in the world. The system is now being expanded beyond the trial sites to include all of the company's North Sea locations, and applications at other onshore and offshore facilities are being considered. The new system provides accurate data to support the reporting requirements of expected UK Government carbon emissions reduction and energy efficiency legislation. Similar schemes are likely to emerge in other countries. System enhancements and additional performance indicators are being considered to enable a better understanding of energy- use patterns and to make comparisons between different sites more meaningful.