We all identify the need to integrate climate change into corporate strategy, with a profitable Carbon Capture Utilisation & Storage (CCUS) business model the elusive goal. Today, CCUS forms 10% of the R&D program of Total, a founding contributor to the OGCI Climate Investments fund. Here in the North East of Scotland, UK and Scottish Governments, along with project developer Pale Blue Dot Energy and Total are providing match funding to the European Commission’s Connecting Europe Facilities fund to progress feasibility work on the Acorn CCS project. As society continues to drive an expectation beyond hydrocarbons, what proposal might the North East of Scotland offer in response? To meet ambitious emissions reduction targets, the UK must envisage radical changes to the energy economy. Already affecting power generation, these changes must drive further into transport and domestic/industrial energy consumption. Two technologies which may play a part in the decarbonisation of the UK energy business are CCUS and the use of Hydrogen as an energy carrier and energy store, with several studies showing that clean hydrogen is potentially the lowest cost route to meeting UK emission targets in multiple sectors. This builds on the UK’s world class gas network infrastructure, which can be repurposed to avoid becoming stranded, avoiding the enormous expense of increasing the capacity of the electricity transmission network, much of which would lie idle during the summer. The UK gas network carries approximately three times more energy than the electricity network, at one third the unit cost to consumers, and meets winter peaks that are five times greater. Different to previous CCUS projects, and having the Oil and Gas Authority (OGA)’s first carbon dioxide appraisal and storage licence award, ACORN is an opportunity to evaluate a brownfield CCUS solution to capture, transport and store post-combustion CO 2 , combined with an upside through emerging pre-combustion CO 2 capture technology relating to the production and sale of bulk hydrogen produced from natural gas with a zero-emission target. Located at the St Fergus Gas Terminal – an active industrial site where around 35% of all the natural gas used in the UK comes onshore. ACORN is designed as a "low-cost", "low-risk" CCUS project, to be built quickly, taking advantage of existing oil and gas infrastructure and well understood offshore storage sites. The Acorn Hydrogen project undertakes to evaluate and develop an advanced reformation process which will deliver the most energy and cost-efficient industrial hydrogen production process whilst capturing and sequestering CO 2 emissions. An initial phase offers a full-chain demonstration project, an essential step toward commissioning the concept and subsequent commercialisation of large-scale CCUS and Hydrogen deployment in the UK. SPE Offshore Europe represents an ideal opportunity to update both the region and industry on results, observations, and conclusions with respect to the evolving development architecture, selected process technologies, Government and gas transportation regulatory engagement as this, the leading Scottish CCS project continues its journey toward a final investment decision.

The major challenge facing society in the 21st century is to improve the quality of life for all citizens in an egalitarian way, by providing sufficient food, shelter, energy and other resources for a healthy meaningful life, whilst at the same time decarbonizing anthropogenic activity to provide a safe global climate. This means limiting the temperature rise to below 2°C. Currently, spreading wealth and health across the globe is dependent on growing the GDP of all countries. This is driven by the use of energy, which until recently has mostly derived from fossil fuel, though a number of countries have shown a decoupling of GDP growth and greenhouse gas emissions from the energy sector through rapid increases in low carbon energy generation. Nevertheless, as low carbon energy technologies are implemented over the coming decades, fossil fuels will continue to have a vital role in providing energy to drive the global economy. Considering the current level of energy consumption and projected implementation rates of low carbon energy production, a considerable quantity of fossil fuels will still be used, and to avoid emissions of GHG, carbon capture and storage (CCS) on an industrial scale will be required. In addition, the IPCC estimate that large scale GHG removal from the atmosphere is required using technologies such as Bioenergy CCS to achieve climate safety. In this paper we estimate the amount of carbon dioxide that will have to be captured and stored, the storage volume and infrastructure required if we are to achieve both the energy consumption and GHG emission goals. By reference to the UK we conclude that the oil and gas production industry alone has the geological and engineering expertise and global reach to find the geological storage structures and build the facilities, pipelines and wells required. Here we consider why and how oil and gas companies will need to morph into hydrocarbon production and carbon dioxide storage enterprises, and thus be economically sustainable businesses in the long term, by diversifying in and developing this new industry.

This paper will discuss when it is advantageous (in the context of an offshore oil and gas environment) to process data at the network edge (in close proximity to equipment assets) or to stream data to a cloud-based Internet of Things (IoT) platform for analysis. It will offer an objective assessment of both approaches and provide recommendations for securing data in both cases, as part of an overarching cybersecurity strategy. IoT has opened the door to significant efficiency gains in the oil and gas industry. This is particularly the case in the offshore sector, where there is a pressing need to reduce costs and maximize equipment availability. In some cases, it is advantageous to process data in close proximity to equipment assets (i.e., at the edge). In others, it makes more sense to securely stream data to a cloud- based IoT platform and harness artificial intelligence (AI) to aid in decision making. In certain cases, both architectures can be utilized in compliment to one another. Many factors need to be taken into consideration when evaluating an edge or cloud-based approach. Some of these include data volume, transmission and processing speed, control of data, cost, etc. Edge computing can be used to streamline and enhance the efficiency of data analytics. In certain applications, this can mean the difference between analyzing a performance failure after the fact, and pre-empting it in the first place, which in the offshore environment could potentially translate into millions of dollars per day. On the other hand, there are situations where it is beneficial to store large volumes of data on a cloud-based platform. For example, if the goal is to leverage advanced IoT-based industrial analytics to optimize an entire fleet of a certain type of equipment, the cloud may be the best solution. Cybersecurity is another consideration. Attacks on critical infrastructure have risen significantly over the course of the past year. As more Intelligent Electronic Devices (IEDs) are deployed in the oil and gas industry to optimize efficiency, Industrial Control Systems (ICSs) are increasingly vulnerable. As a result, the threat extends beyond proprietary data to mission-critical operational technology (OT) assets and equipment. Cybersecurity standards and layered, defense-in-depth models have grown in response to the frequency and sophistication of cyber attacks. Additionally, recent advances in cyber defense technology incorporate small, kilobit-sized embedded software agents to monitor networks for anomalies that could signal an intrusion. This paper will explore new cybersecurity threats to oil and gas assets, as well as strategies operators can employ to defend against them, whether using an edge or cloud-based platform, or both.

The UK and the international community have an increasing interest in the benefits of a hydrogen-based economy. Existing and emerging technologies that are inherently carbon-neutral and potentially carbon-negative are increasingly attractive, given the challenge of meeting climate targets to prevent climate change and build a clean growth strategy. The integration of clean energy technologies across the UK Continental Shelf (UKCS) can increase the flexibility of the energy system, driving efficiency, cost reduction and enhancing the value of natural resources. There are over 250 platforms and 45,000 kilometres of pipeline installed within the United Kingdom Continental Shelf (UKCS). As these assets near the end of their economic life oil and gas operators are planning to decommission these facilities in an efficient and cost-effective manner. Current cost forecasts for this activity exceed £58bn with approximately 50% borne by the operators and 50% borne by UK taxpayers. The Hydrogen Offshore Production (HOP) project identifies an alternative to decommissioning by providing re-use options for offshore infrastructure while addressing the national challenge of a low carbon energy supply. In doing so, the project will prove the feasibility of several decentralised hydrogen generation, storage and distribution options that collectively provide a scalable offshore hydrogen production solution, whilst offsetting a portion of decommissioning costs that are currently forecast for all offshore assets and infrastructure. HOP will tackle the challenge of bulk hydrogen production by (1) proposing viable environmental and economic technology solutions to be deployed offshore, (2) developing a new Industrial Hydrogen Production test site to both prove the industrial benefits and to aid commercialisation of emerging technology and, (3) conducting market analysis and producing the business case for the transformation of existing offshore infrastructure, re-purposing assets and demonstrating the viability for decentralised generation of hydrogen. As part of the project, an Industrial Hydrogen Production test site will be established with Flotta (Orkney Islands) being proposed as the location. This will provide a test bed for technology, fast-tracking its development and providing a route for accelerated commercial deployment. Within a region of considerable renewable energy generation, the island of Flotta is ideally placed to benefit from local expertise, existing supply chain and advanced technology solutions. For example, the Industrial Hydrogen Production test site would greatly benefit from lessons learnt at the nearby Orkney Water Testing Centre.

This paper's focus is the advocation of utilising diagnostic data available from digital field devices to help reduce operating costs for end users. In recent years companies across multiple industrial sectors have invested in improving their understanding of both the historical and live data they produce. The source of the data is specific to the processes but the objective for all remains the same - to use statistical techniques to develop a toolset that can be used to predict performance based on live and historical data. For the oil and gas industry, the continued adoption of digital device transmitters has increased the volume of data available from instruments such as flow meters, temperature probes and pressure sensors. Typically, this additional data provides information on the integrity or quality of the associated device. However, with the appropriate level of facility and instrument knowledge it is also possible to infer information with respect to the process stream. Furthermore, this data, if correctly interpreted, can be used to predict maintenance and calibration requirements, resulting in reduced staff effort and shutdowns. The need for physical intervention due to device failure is also reduced, which in turn minimises the potential for accidental hydrocarbon release when a device is removed for repair or replacement. NEL are currently undertaking research projects with the primary objective of developing definitive correlations between process effects, meter condition and diagnostic data response. The paper provides details of said research, with particular reference to the data science and mathematical techniques currently being trialed for the analysis stage. The techniques, when fully developed, will be metering technology specific and therefore offer a level of insight to end users on facility and meter performance which is not currently available in industry. The toolsets developed will in turn provide the end users with the knowledge and confidence to make cost saving decisions with respect to planned maintenance as well as improving facility efficiency through a more comprehensive understanding of their own data sets.

The United Kingdom Continental Shelf (UKCS) is a mature region with around 42 billion barrels of oil equivalent produced since the late 1960s. The majority of the remaining estimated 15 billion barrels of oil equivalent reserves lie in more technical and challenging areas. To produce these reserves, access to existing infrastructure through subsea tiebacks for new and incremental projects or as new standalone development projects remain key to the future of UKCS and slowing the recent production decline. Currently, about 60 percent of all new fields in the UKCS are subsea tiebacks to existing infrastructure and there is an increasing interdependence for both production facilities and transportation infrastructure 1 . Many recent discoveries have been comparatively small and are not large enough to support their own infrastructure. This paper attempts to answer this critical question: how does the separation of infrastructure and field ownership affect economic recovery in a mature oil basin? We explore how possible different ownership structures and access arrangements might affect the economic viability of the remaining UKCS reserves by applying a mixed integer-programming model to field data from the Northern North Sea. Specifically, we consider the impact of a changing tax regime in a way that is relevant and consistent with unbundling infrastructure provision through cost sharing arrangements and how this affects the long-term economics of hubs and their user fields. The model is used to maximize the net present value of regional production (the maximum economic exploitation of the region) by determining the optimal set of new developments, tiebacks from fields to hubs, and timings of hub and field shutdowns. The effects of the separation of infrastructure and field ownership are captured by individual field and infrastructure viability conditions constraints.

The economics of small gas field developments in the Southern North Sea away from any existing infrastructure is particularly sensitive to subsurface uncertainties. Applying latest geophysical approaches is a key aspect of obtaining sufficient grip on these parameters and ensuring robust project economics. For the Alpha field, the structural uncertainty due to poor seismic imaging was identified as critical and therefore a dedicated seismic imaging project was undertaken. It involved re-processing the existing seismic data with the latest velocity modeling and imaging technologies, such as Reverse Time Migration. It led to a clear improvement of the seismic character at objective level as well as a more consistent depth image. As a consequence, the expected volume of gas in place increased by 50% and additional reservoir targets were identified, considerably improving the project economics. In addition, a High Definition 3D seismic image of the shallow subsurface was for the first time successfully created over the area to assess any potential geohazards and ensured that the proposed and selected development concept had mitigations against these hazards and their consequences.

This paper describes how Ocean Power Technologies (OPT) successfully transferred technology developed in the Renewables sector to Defence and is currently repeating this process for the Oil & Gas (O&G) market, providing solutions that could drive down project OPEX & CAPEX to help make current fields that offer low commercial returns more attractive for development. OPT describes the core enabling technology viz a moored, floating buoy which harvests wave energy and uses a proprietary energy management system to deliver persistent power and communications over long period multi-year deployments. It will describe a versatile marine platform which enables a wide variety of new application solutions. The system is known as an APB-350. The results of the latest deployment of the APB-350 are described, illustrating the ability to deploy remote, in-ocean sensors and communications for subsea applications, and demonstrating the rugged survivability of the device. It will be shown that the technology can deliver to operators a cost effective, safe, reliable, persistent power and communication platform that has the potential to reduce operational costs and improve overall production performance. Specifically, where development would traditionally require high cost power delivery systems, the technology can provide an economic solution where previously the cost was prohibitive. Potential applications are discussed in collaboration with Premier Oil such as: UUV garages for in permanent infield monitoring/inspection of assets The control of electric trees for CO2/water field injection Environmental monitoring for pre-post deployment Real-time on site field monitoring/sensing systems for 4D reservoir analysis and pre/post deployment surveys Security Cordons for offshore developments Temporary navigational markers for surface & submerged structures Conclusions will be drawn regarding how the transfer approach used will benefit the oil and gas industry, to improve current operations and deliver alternative, more cost effective solutions. The ability to power alternate sensor packages and high power delivery functions, will enable operators to obtain, real-time data for remote field operations; thus allowing remote real-time asset management and enabling better monitoring and control of overall performance and safety.

Abstract The Laggan and Tormore gas condensate fields are situated in 600m water depth some 140km north-west of the Shetland Islands. The region is served by limited oil and gas infrastructure and so called "stranded gas" fields have been left undeveloped to date; primarily due to the significant investment required to establish an export route to market in this remote and harsh environment. After several years of extensive development engineering studies and commercial negotiations, the Laggan and Tormore partners, led by TOTAL E&P UK Ltd (TEP UK), are moving towards sanction of a major project that could lead to first production of gas from this challenging region by 2014. The proposed project facilities consist of a subsea template-manifold above each of the Laggan and Tormore reservoirs with production from up to eight subsea wells commingled and exported multiphase to the Shetland Islands via two 18" 140km rigid steel flowlines. A new gas processing facility sized for 500 MMscfd and operated by TEP UK will be constructed onshore close to the existing Sullom Voe oil terminal. A new 30" 230km gas export pipeline sized for circa 665 MMscfd will transport the processed gas to a tie-in point on the FUKA pipeline close to the abandoned MCP01 platform. Development of the Laggan-Tormore gas fields would represent a major achievement for the license partnership and a significant milestone in the overall development of the West of Shetland region. The "Shetland Islands Regional Gas Export" system (SIRGE) will offer a new export route for gas from an area previously bottlenecked by the existing limited gas export infrastructure. Linked to the new onshore gas processing terminal, SIRGE should reduced the development cost for new entrants, thereby promoting the future growth potential of the region. The West of Shetland region is unique for its combination of extreme metocean conditions and a demanding environmental context characterised by its distinctive wildlife and rugged onshore terrain. The long distance subsea tie-back chosen for Laggan-Tormore brings with it significant technical challenges in terms of flow assurance and construction / installation planning together with a complex regulatory framework associated with environmental considerations, multiple stakeholders and land access approvals. Reaching this milestone has involved a significant investment in both financial and human resources to complete the technical engineering and sub-surface studies as well as the complex commercial negotiations to define the eventual development concept and gas evacuation route. The Third Party Investment Process carried out in 2008 offered the key West of Shetland stakeholders an opportunity to invest in a gas evacuation system sized for the region. This paper summarises the Laggan-Tormore development process to date as well as the key technical challenges to bring this major new project to fruition and establish a new gas export infrastructure serving the West of Shetland region in years to come.

Abstract Production Engineers have more and more information available and operating companies are trying to integrate that information and create an "integrated oil-field" with the main objectives of maximizing production and at the same time maximize recovery. One of the challenges in these types of approaches is the quality of production data. By not having accurate enough production data, the integration efforts are covered in a layer of haze, uncertainties. By combining advanced data validation and data reconciliation techniques it is possible to improve the quality of production data and quantifying all flows, temperatures, pressures and compositions throughout the production network. This technology has been applied in the downstream area for years and are now more and more being deployed in oil and gas production. The main goal is to provide accurate flow of oil, gas and water in each production well, but it can and has been applied to water injection systems, gas fuel and flare systems, FPSO's etc. It has been shown that it is possible to provide accurate production data in a production network. In particular, it has been shown that even on wells that do not have multi phase flow meters, it is possible to determine the flow of oil, gas and water with an uncertainty of less than 10%. In addition it provides other types of virtual meters, in general a production network with x measurement, would have another 2*x measurements validated and reconciled. Also by comparing measured data with validated and reconciled data it is possible to draw some conclusions; for example sensors and equipment that need maintenance can be identified much earlier and maintenance can move towards conditioned based, predictive maintenance. This is a digital technology that can help operators have a better understanding of how their assets are performing and can help in increasing recovery from each well in the production network. Injection schemes can be performed more optimally and capacity from a field can be expanded in a cost effective way. Introduction This paper focuses on the importance of data quality for the new real-time data infrastructures, so-called "integrated oil-fields", currently being developed and deployed in oil and gas production. The paper is organized as follows: Starting with a brief introduction of the concept of the new real-time data infrastructures and advanced data validation and reconciliation. This is followed by a description of the problem in oil and gas production that these infrastructures are trying to address and the problem of data quality in these infrastructures. The concept of data validation and data reconciliation used to enhance data quality is introduced and the potential benefits are shown. Finally results from applying advanced data validation and reconciliation in oil and gas production are presented including benefits attained and conclusions. Integrated oil-fields. "Smart fields", "e-fields", "field of the future", "digital oil fields" and "field monitoring" are all names of real-time data infrastructures aimed at providing information for decision making. Depending on the company, the approaches varies somewhat but most of them contains three or four distinct layers included in a closed loop: surveillance, integration, optimization and if there is a fourth layer, it is usually related to innovation. The surveillance layer, also referred to as automation and communication infrastructure, consists of both hardware and software and provides continuous monitoring of production data and Key Performance Indicators (KPIs). The integration layer, also called remote performance management, aims at providing the right person with the right information at the right time. The optimization layer provides a model based decision support system and a defined workflow needed to optimize both wells and facilities (short loop) and reservoirs and facilities (long loop). The fourth layer, innovation, is where lessons learned and experiences are summarized and used to improve the first three layers.

Abstract Despite having been explored for over 40 years, 3.6 billion barrels of oil equivalent have been discovered in the last five years in north west Europe. On average US$2.4 was spent on exploration for each barrel found in the offshore region. This unit finding cost is comparable to that in the deepwater Gulf of Mexico over the same period, one of the global hotspots for exploration. The largest volumes of reserves were found in Mid Norway where 1 billion barrels of oil equivalent has been discovered in the last five years. Despite this apparent success, only one of the 11 fields found in the sector is currently expected to be developed before 2012. Gas export capacity from the region remains an issue. The North Sea itself attracted 75% of the exploration expenditure over the last five years and 2 bn boe of reserves were discovered. Finding costs ranged between US$2.5/boe for the Norwegian North Sea to US$3.5/boe for the UK Southern Gas Basin. Although significantly higher than the US$1.5/boe unit finding costs in Mid Norway, over 50% of these reserves are expected to be developed within five years. Industry cost inflation and lower discovery sizes have resulted in the finding costs of the last five years doubling from the previous five. However, with a record number of exploration licences being held, US$2.5 billion being spent on exploration last year and substantial finds still being made, there will be many more exploration success stories to come in the region. Introduction The offshore regions of north west Europe have been explored for more than 40 years, over which time 4,000 exploration wells have been drilled. The core areas of the North Sea in particular, have undergone intensive exploration with 30 exploration wells drilled on some blocks. Unsurprisingly the average size of new discoveries has reduced since the early days and in the late 1990s and early part of this decade there was a significant drop in the number of wells drilled in the region. The dramatic drop in oil price and the mega-mergers at that time caused companies to rethink their global exploration strategies and the perception of the North Sea as a mature province, coupled with the opening up of new global provinces, resulted in a smaller proportion of exploration budgets being allocated to the sector. More recently interest in north west Europe exploration has returned and the number of companies holding licences in the region has risen by 50% since 2002, from 163 to 248. This has been driven primarily by the increase in oil and gas prices, but has also been encouraged by fiscal incentives, regulatory changes plus a number of high profile discoveries. Countries and regions are effectively competing for exploration spend. Overall, north west Europe has been successful over the last five years in attracting exploration investment despite global cost inflation and a reduction in the volume of reserves discovered. North west Europe offers a wide spectrum of exploration drilling opportunities from frontier regions such as the Barents Sea, to step out wells from existing developments. Recent exploration wells have been drilled in water depths ranging from 20 metres to nearly 2 kilometres. In addition, new play concepts are still being tested and technology is constantly being pushed. Notably, major steps forward have been made in high pressure / high temperature (HP/HT) drilling. Methodology The numbers in this paper are based on Wood Mackenzie's upstream database. The information is collated from a range of public domain sources plus feedback from operators and participants across the North Sea. The final numbers that are in the database are Wood Mackenzie's view based on analysis of the information that was available. Well cost data is based on estimated costs per well which has been compared to reported government and company figures in each country or region. Wood Mackenzie's global well cost database includes 190 countries where any significant exploration has taken place. The only notable provinces excluded are the onshore US, the US Gulf Shelf and Eastern Europe.

Abstract Carbon Capture and Storage (CCS) has been receiving increasing recognition as a short to medium term measure for closing the energy gap whilst a portfolio of carbon neutral technologies is developed to provide power for the UK. This has been accompanied by an increasing political will and a developing policy framework to achieve it. If the UK is serious in its intentions, the necessary economic drivers will also be put in place. It remains to identify and resolve the technical issues that apply peculiarly to the UK. In recent years the capture technology has developed to the point of viability and storage has been accepted to be safe and ecologically sound, but relatively little work has been carried out on CO 2 transport. In the US naturally occurring CO 2 is routinely transported considerable distances overland through mostly sparsely populated regions for the purpose of enhanced oil recovery. There is also some limited transport of anthropogenic CO 2 . In the UK a number of suitable offshore CO 2 sinks have been identified in the North and Irish Seas for EOR or simply for storage. It has been commonly assumed that the transport of CO 2 from UK sources to offshore sinks is straightforward, and may even be able to make widespread use of existing infrastructure. However, there are significant differences between the US experience and the UK transport requirements. The UK will be dealing with anthropogenic CO 2 , mostly from power plant, which will impose constraints on the hydraulics that have not yet been fully explored. Considerable proportions of the transport system will be subsea, of which there is as yet virtually no experience. There are questions as to the suitability of much of the existing infrastructure and the desirability of using it. There is little experience with multi-source transport systems through densely populated regions. This paper will address some of the technical issues that need to be considered for the development of a UK CO 2 transport infrastructure, in the post demonstration phase of carbon capture and storage, capable of mitigating the emission of green house gases whilst allowing the continued use of fossil fuels. Introduction It is now widely accepted that the climate of the earth is changing due to the warming effect of increasing levels of greenhouse gases in the earth's atmosphere. The increase in greenhouse gas levels is predominantly a result of human activity, particularly in the burning of fossil fuels. In order to prevent catastrophic climate change, CO 2 equivalent concentrations need to be stabilised at a level that can be regulated naturally. However, the worldwide demand for energy is also increasing and in the short to medium term it cannot be met by using zero-emission technologies such as renewable energy sources or nuclear energy. Carbon capture and storage provides a bridging technology to close this energy gap whilst still meeting emissions targets until alternative carbon neutral technologies can be developed. For this reason in the G8 2007 Summit Declaration there has been a statement of commitment by governments to CCS that states [1] "In recognition of the increasingly urgent needs to achieve longer term greenhouse gas abatement, we will work on accelerating development and deployment of carbon capture and storage" CCS technologies offer particular advantages in that they allow a balance to be struck between the increasing demand for energy, particularly from coal, with the requirement to reduce emissions from this sector.

Abstract Historically, gas production to the Bacton gas terminal from the southern UK sector of the North Sea has been predominately lean gas.In the recent years fields producing richer gas have been added to the production system, bringing significantly increased condensate production.While the condensate is itself a valuable product, the increased volumes have raised a number of liquids management challenges both for offshore and onshore operations. To address these challenges, a software-based operational guidance system has been deployed over a broadly integrated scope that includes onshore and offshore components.This system includes performance monitoring and operational guidance for the offshore compression stations, liquids and gas quality management for the offshore production system and operational guidance for the onshore plant.The implementation is well-aligned with SmartFields architectural approaches.This paper details the business case, the technical approach and the experience gained both in the implementation and operation of the system. Introduction The Shell operations in the Southern North Sea has for some time been a mature dry gas basin, which has been well served by low temperature gas conditioning in a relatively simple on-shore terminal. Over the past few years, much richer gas has been produced from newly developed fields. At the same time, changes in the gas market have pushed the business there from traditional long-term contracts, towards a focus on the production of direct market gas. These two factors have had a pronounced effect on opportunities for growth and performance improvement. Understanding liquids management throughout the system and improving liquids capacity in the terminal are seen as important levers for delivering both new production opportunities and an overall performance improvement. At the same time, recent organizational changes have resulted in an increased need for clear communication between multiple business and operational sites. For the UK Southern North Sea, for example, offshore operations are located both at Bacton and at the Leman hub. The onshore plant is supported by staff located at Bacton and advice can be given from other Shell EP Europe locations. Gas scheduling functions are performed in Aberdeen. Thus, there is an increased need to provide distributed data and documentation of operational decisions and processes between the various locations.

Abstract The traditional industry methods and processes used for managing production operations and optimising well performance highlight a significant gap in integrating daily production operations with reservoir management. The consequence can be a reactive production management process that results in deferred production or suboptimal asset performance. This case study illustrates how a real-time well surveillance service was successfully implemented in a mature North Sea oil field, resulting in a significant production performance improvement and increased flexibility and visibility in managing production from the asset. Introduction Secure delivery and control of production data among wellsites and data management systems are key functions for production and reservoir surveillance. Data sharing among multiple parties, such as the operator's onshore technical experts, platform operations, and service company personnel, provides value-added interactions that enhance operations and production performance. The traditional methods used for data gathering from production facilities typically show that data quality is compromised (particularly downhole monitoring devices that have data sampling frequencies of 1 to 15 sec) and thus cannot be used for high-quality production optimisation and reservoir analysis by users who are remote from the facility. The introduction of more advanced monitoring and control technologies will allow more difficult fields to be developed and extend the life of mature fields. This will be made difficult, or even impossible, if the disconnect between production operations (with large amounts of streaming data for process control), and the E&P domain (in which large amounts of integrated flat file data are used in a variety of software engineering applications) is not bridged. This paper illustrates how a real-time data acquisition and control system securely communicates with a remote data management system to achieve streaming of high-quality data from existing and new downhole monitoring devices, allowing event notification and remote advice for the control of wellsite functions. The solution is based on emerging information technologies for secure data transmission and bidirectional communication. In this way, systems can be quickly deployed at the wellsite using only standard physical communication links (fibre, satellite, cellular, Internet, etc.), making them independent of communication service and legacy infrastructure. The data can then be securely accessed and downloaded by multiple users via standard desktop personal computer (PC) Web browsers over their intranets or the Internet. The architecture of a scalable solution and its implementation on the Harding platform in the North Sea to provide secure connectivity via standard Transmission Control Protocol/Internet Protocol (TCP/IP) connections are covered in this paper. We also explain how this system is being used collaboratively by the onshore and offshore team members and the service providers to optimise production operations and manage the reservoir in ways not previously possible. Brownfield Challenge Production from the Harding field started in April 1996. After experiencing a 2-year production plateau with rates in excess of 80,000 bbl oil equivalent per day, the field went into a sharp decline during 2000 as a result of rapidly increasing water cuts. By early 2001 production was declining at a rate of 3,000 BOPD/month. The asset team was faced with the traditional brownfield challenge of optimising production and arresting decline while managing the topsides and reservoir management constraints. Following a comprehensive review of the field and production operations, the 2002 decline rate was reduced to 1,000 BOPD/month and the field is now experiencing a second plateau of over 60,000 bbl oil equivalent per day ( Fig. 1 ). Significantly, average production in 2002 was higher than in 2001.

Abstract BG Group's Hydrates Gas-to-Solids (GtS) technology has been established to investigate ways of managing gas in regions lacking suitable gas infrastructure and/or local markets. Put simply, the technology amounts to adding natural gas to water and stirring. This converts the gas into hydrate that is then shipped to market for regasification to supply power generation facilities or other gas customers. The low complexity of this technology and the potential for small-scale modular operation is particularly appropriate for offshore associated gas applications where growing environmental pressures to reduce or eliminate gas flaring frequently create situations in which oil developments cannot proceed if there is no technical or economic means for gas disposal. BG is progressing further pilot plant scale testing and engineering definition programmes with the aim of targeting a potential commercial plant operation by 2006. Introduction The Hydrates Technology Programme was launched by BG in 1993 to investigate ways of establishing a low cost alternative means of transocean gas transportation. The technology entails converting the gas into a hydrate that is then shipped to market and re-gasified at the delivery point. To date, the technology development has been undertaken for BG by Advantica Technologies Ltd (formally BG Technology) and has included laboratory testing, construction and testing of a pilot plant and preliminary engineering and commercial realisation studies. Natural Gas Hydrates. Natural gas hydrates are crystalline solids composed of water and natural gas in physical combination where individual gas molecules exist within ‘cages’ of water molecules and are more familiar in the Oil and Gas Industry as a traditional nuisance for their propensity to block pipelines if precautions, such as chemical inhibition, are not taken. However, establishing a comprehensive understanding of their behaviour has allowed BG to investigate the possible positive application of gas hydrates for transoceanic gas transportation. Dry Hydrate Technology. The initial focus of the Hydrate Technology programme was on bulk gas transportation with the technology being deployed as either floating offshore or coastal onshore facilities. Considerable work was undertaken including: Extensive laboratory testing enabling reactor design and process model validation Construction and testing of 1 tonne/day pilot plant Development and application of dewatering techniques Long term hydrate storage at stable conditions and controlled regeneration of gas from storage Techno-economic studies Shipping studies The decision was then taken to target stranded associated gas as entry into the gas transportation market and development switched to investigating a lower cost slurry process for smaller gas volumes. Slurry Hydrate Technology. Technology for handling offshore associated gas, such as GtL, LNG, CNG, etc., has received increasing interest in response to the pull from the Oil and Gas Industry for technology solutions to dispose of and/or monetise associated gas, which is often viewed as a nuisance, and the push from governments and environmentalists to prevent its flaring. However, there remain considerable barriers and challenges before the technology can be marinised.

This paper was prepared for presentation at the 1999 SPE Offshore Europe Conference held in Aberdeen, Scotland, 7–9 September 1999.

This paper was prepared for presentation at the 1999 SPE Offshore Europe Conference held in Aberdeen, Scotland, 7–9 September 1999.

In recent years in the U.K.C.S, small fields have been successfully exploited both as satellites to existing infrastructure and as standalone projects using floating production techniques. Amerada Hess Limited has pioneered this approach, particularly in two areas in the Central North Sea: Quadrant 15 around the Ivanhoe/Rob Roy and Scott fields and the Fife area in Quadrants 31/39. The former area is close to existing infrastructure and pipelines whilst the latter is over 30 Kms from the nearest facility. The search for these small fields in the North Sea has been heralded by the widespread use of 3D seismic which has allowed the identification of much smaller prospective structures and more efficient targeting of exploration wells which may be suspended for use as development wells or later side-tracked for optimum reservoir development. The use of 3D seismic for exploration drilling became more common through the late 1980's and early 1990's. Such data-sets have helped to more accurately image small, often low relief structures and to optimise the location of exploration and appraisal wells which are often few in number in order to sustain viable economic margins. In parallel with geophysical developments, advances in offshore engineering technology have helped to achieve lower capital expenditure so necessitating much smaller reserve sizes to make tie-backs economic. The Ivanhoe and Rob Roy fields were discovered in 1975 and 1984 respectively by Monsanto. Each field was developed via a sub-sea manifold connected to a converted semi-submersible production facility. Two years after government approval of the joint Ivanhoe/Rob Roy development plan saw the discovery of the Hamish Field. To date this small field has produced just over 3 million barrels of oil from a single producing well. It is currently producing about 500 BOPD. The importance of sustaining production from the Ivanhoe/Rob Roy facility has resulted in the exploration for other small structures which might be tied back prior to the end of field life. Understandably, exploration in such a mature area does not always meet with success as the structures which are now being targeted are difficult to image on 3D seismic as they are frequently in structurally complex areas. Where successful pools are encountered, their tie back is often facilitated by similar reservoir and fluid properties making existing development facilities compatible. In the Central North Sea, the Angus field produced some 11 million barrels of oil through a Floating Production and Offshore Storage Facility prior to its abandonment in 1991. A similar development plan is scheduled for the Fife field where reserves are currently estimated to be some 34 million barrels of oil with the start of production planned for September 1995. Recent exploration in the Fife area has been targeted at finding accumulations which may be tied back as the field comes-off plateau production. In 1994 a 3D data-set was acquired over a structure to the south-east of Fife, the provisional well location chosen on 2D seismic data was optimised and the well was drilled encountering what is now known as the Fergus field. This structure has a small reserve base which would otherwise be uneconomic if developed as a stand alone field. It is hoped that this structure may be tied back to Fife as it comes off plateau. P. 79

P.J. Smith, BP, and M. Daly, BP, and M. Stump, BP. Abstract Oil was discovered West of Shetland's as long ago as 1977 with the Clair discovery. However the first oil to be placed upon long-term production will not be until 1996 with the BP/Shell development of Foinaven. Developed during those 20 years is a wealth of experience gained by the offshore industry in discovering, appraising and developing oil fields in the UKCS providing the foundation for opening up the new West of Shetland Province. The continued commitment to explore West of Shetlands, despite a sequence of non-commercial discoveries and dry holes led to the 1992 recognition of Foinaven and subsequently its fast track to development. The paradox of twenty years from oil discovered to oil produced in a province, against 4 years for Foinaven discovery to market is the central inquiry of this paper. Fundamental to understanding this paradox are: the environmental constraints, the development of new technology, the awareness of the business prerogatives, and the new behaviours of all stakeholders. We take the case history of the Foinaven field development and discuss the requirements to bring this project forward. Direct hydrocarbon detection seismic technology, novel well techniques and extended well testing provide the basis for volumes and productivity predictions. The employment of facility solutions in harsh metocean conditions and deep waters provide no less of a technological challenge. Understanding fully the business process and the importance of pace in development against the uncertainties that such a pace invokes is paramount. The quality and maturity of the UK offshore industry is an often forgotten component, along with the strides that oil companies and regulatory bodies have made in clearing hurdles for compliance in moving together at pace. We are left with the challenge of developing, appraising and exploring simultaneously in a new province not knowing the full extent of volume, technology or behavioural change that it will require. Background Oil was discovered West of Shetland as long ago as 1977 with the Clair discovery. 15 appraisal wells have been drilled with a 3D seismic survey completed in 1990. Various reasons have been used to slow the pace of development of Clair, principally the poor productivity of the wells, the distance from infrastructure and severe metocean conditions. All are reasonable and based upon evidence from the nearly 20 years of studies work. The salient fact, however, is that Clair still awaits development even though oil in place estimates place it between 3.5 and 6 billion barrels, which is in the giant class for field size, and potentially makes it the largest accumulation in the UKCS. The first oil to be produced long-term from the West of Shetland will be in 1996 from the BP/Shell development of Foinaven. Although the first well was drilled in 1990, in reality Foinaven was not discovered until 1992 with the second well. The rapid appraisal of the field concentrating on 5 appraisal wells in 1994, including an extended well test, led to sanction of the project in 1994 and involved parallel subsurface, facility and commercial studies. Development drilling and facility construction in 1993 will lead to oil early in 1996. Why then will oil be produced from Foinaven rather than Clair in a period of intense activity in the UKCS. In those same 20 years of Clair appraisal, 118 new fields have come on to production in the UKCS leading to a production total of 9325 mmb, which is almost half of the total cumulative UKCS oil production to date. P. 81

Abstract Development of the Hudson field took place over the period December 1992 to January 1995. This was a time of generally low oil prices and one in which the combined effects of oil price, smaller discoveries and diminishing reserves but increasing development and operating costs, were being faced by the industry. The Hudson field development was conceived under these circumstances and demanded that a cost effective solution be identified in order to make the development viable. Initial studies of conventional stand-alone and tie-back options, whilst endorsing the commerciality of the project, failed to maximise its economic potential or to meet the business-driven objectives of the co-venturers. In light of this, an innovative two-phase development was devised, utilising a leased FPSO for the first phase of production and a subsea tie-back to the Tern platform for the second phase. This gave the benefits of an optimised reservoir development plan for the second phase, minimum capital outlay at the front end and early production and generation of cash-flow, which effectively financed the main field development. In addition to this novel facilities solution, the development also implemented many of the concepts which have since become synonymous with the industry's CRINE initiative, most notably the use of functional specifications, standard components, minimum operator intervention in contractor/supplier activities, minimum size of operator's management team and a novel contracting strategy, giving greatest opportunity for cost savings. The net result of these various initiatives was completion of the facilities installation and commissioning two months ahead of the targeted first oil date and at a cost of 29% below the original budget. Field Location/Description The Hudson field is located in 157 metres of water in Blocks 210/24a and b of the northern North Sea and at the western edge of the East Shetland Basin (fig 1). It is the most westerly of the Brent group of fields, the Tern platform lying 11 kilometres to the east and providing the closest point of access to the Brent system infrastructure. Participants in the field are:- Amerada Hess Limited: 28A62% Cieco UK Limited: 25.769% Mobil North Sea Limited: 20.000% Shell UK Limited: 12.885% Esso Expro Limited: 12.885% The field was discovered in 1987 by the then Operator, Amoco UK Ltd. In 1988, Amoco disposed of its equity share to Shell/Esso, with operatorship passing to Amerada Hess Ltd. A development plan was subsequently submitted to the DTI in October 1992, with approval being granted at the end of that year. The reservoir sandstones in the Hudson field are assigned to the Brent Group which comprises five formations; Tarbert and Ness which form the Upper Brent Unit and Etive, Rannoch and Broom, forming the Lower Brent Unit. As with many Brent sandstone oilfields, significant heterogeneities are present within the formations and in addition, variation in sand quality at the layer boundaries affects vertical transmissibility. At the time of preparation of the Field Development Plan appraisal data was limited and oil water contacts (different for Upper and Lower Brent) were inferred from IFFT pressure measurements and were therefore uncertain as pressures in the field were affected by other field developments in the basin. This, coupled with ranges and uncertainties assigned to seismic depth conversion, oil saturation, net to gross ratio and possible erosion, led to a range of Stock Tank Oil In Place estimates (STOIP) of between 109 and 341 mmbbls, the most likely figure being 209 mmbbls with corresponding recoverable reserves of 86 mmbbls. Anticipated peak production of oil was 46 MBPD in year one, an annual average rate of 38 MBPD and a forecast field life of 12 years. Peak fluids production rate was predicted to be 55 MBPD. P. 219