MED OIL Magazine Summer Autumn 18 by Rosendahls_online

MED OIL & GAS

Summer/Autumn Magazine 2018 1

INTRODUCING OUR 15,000 PSI SUBSEA CHOKE VALVE

SPECIFICATION TECHNOLOGY – None Retrieve Subsea Choke – ISO 10423 ‘HH’ Material Class – 600 Meters Water Depth Qualification

MATERIALS – Body ASTM A182 F22 c/w Alloy 625 Overlay – Solid Tungsten Carbide Trim

SPECIALIST COMPONENTS – 8x Stage Multi-Spline Trim – Trim Debris Flushing Mode Feature – Low Flow Control Capability

SAFETY – Safely Handles Pressure Drops of 800 Bar – Velocity Control Principle Helps Prevent Erosion

www.kentintrol.com/subsea Tel: +44 (0)1484 710311 | Email: info@kentintrol.com KOSO Kent Introl Limited is part of the KOSO Group of companies.

Content

Features IBM Digitilization helps to drive major improvements in Health Safety and the Environment.............................................6 ABS-Application of HPHT Equipment, next steps for the industry....................................................................................10 Presight Solutions- Increased awareness of barrier status and major accident risk across offshore operations ................14 Antech- Geosteering CTD Using the Drill bit as a Sensor..................................................................................................17 Hexagon- Staying Competitive in the Offshore Industry...................................................................................................22 Deepwater EU- Case Study: Dudgeon Offshore wind Farm Remote Catodic Protection Monitoring System.....................28 Vinson & Elkins RLLP- Legal Challenges and Solutions for Oil & Pipeline Developments in the Eastern Mediterranean...35 DEA Ag- Exploring for Shallow Oil in the Barents Sea.......................................................................................................38 DNV GL - A new non-metallic pipe concept: Thermoplastic Composite Pipe....................................................................44

Conferences................................................................................................................................................... 43, 46, 48, 51

Companies in the news: Stauff- Installation of connectors in marine hydraulics......................................................................................................42 Rotech Subsea Limited- wins major contract in the Middle East.......................................................................................47 Wintershall- update on activities in the North Sea........................................................................................................... 49 Koso Kent Introl- Full Service Subsea Valve Provider........................................................................................................ 53

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Utilizing digitalization to smooth the route to meet functional safety compliance, reduce maintenance and increase productivity The 2016 changes to IEC61511 introduced a number of new clauses adding further obligations to operation and maintenance (O&M) personnel. Prior to IEC61511 Edition 2.0, companies had already been considering how best to meet existing obligations with a reducing workforce. A major constraint was the ability to relate data within several siloâ&#x20AC;&#x2122;d O&M systems with the original assessments and designs stored in various document management systems, databases and spreadsheets. The answer is digitalization. Properly deployed and integrated, digitalization makes it possible to meet the O&M requirements of IEC61511 more effectively and easier than before. Not only is data collected automatically, removing significant effort and opportunities for error, but by relating actual performance to the digitized life cycle data we can sustain safe operations and identify opportunities for improvements.

Digital technologies The insight family of applications form part of ABBâ&#x20AC;&#x2122;s digital portfolio called ABB Ability. These application utilize data from the control and safety system to provide *Insights* from a safety, alarm, operation, asset and process perspective. Naturally a tight integration exists with ABBâ&#x20AC;&#x2122;s System 800xA, however these applications can also be used on 3rd party systems. The SafetyInsight suite of applications provide O&M personnel with automatic snapshots of safety performance, and enables

opportunities to reduce the maintenance burden and improve productivity through 3 focus areas, with a fourth to be launched y the end of this year. The first demand reporting: functional safety standards and safety case regulations require demonstration that safety systems are working effectively to prevent the hazardous events they are in place to protect against. This demonstration is achieved through proof testing and testing that performance standards are being met. These activities requires significant maintenance resources and, in-most cases, require facilities to shutdown and therefore usually become the critical path during a turnaround (TAR). SafetyInsight provides automatic independent verification reports that can be used to demonstrate performance standards are being met and valves equipment is functioning correctly. The automatic generation of this information, removes the time consuming need to manually search through alarms and events logs, enabling quicker start-up following an unplanned shutdown and can then be utilized to defer TARs and proof testing activities or shorten the TAR duration. The SafetyInsight demand reporting package is supporting onshore and offshore assets across the North Sea, contributing to above 99% availability of one particular asset. The second focus area is instrument reliability, which is one of two main O&M themes

Comments from

Karl Watson Global Process Safety Product Managet for ABB Oil, Gas and Chemicals karl.h.watson@gb.abb.com

within Ed 2.0 of IEC61511. The automatic collection and performance comparison can be used to demonstrate equipment is performing better than predicted and therefore extend proof testing intervals or identify bad actors and make the necessary improvements. A Norwegian North Sea operator has claimed a 30% reduction in proof testing requirements due to SafetyInsight. The third focus area and second main O&M theme in Ed 2.0 is bypass management. SafetyInsight bypass / blocklog provides an automatic list of all current and historical bypasses and when combined with OperationInsight can form part of the electronic shift report enabling each shift to approve the list of current bypasses at the start of each shift. The release of the 4th focus area will enable override risk assessments to become more effective and streamlined. 5

Digitalization – How “AI” can impact Health, Safety and Environment Digitalization is a top priority among all major operators. Recent slogan of “lower for longer” oil prices may soon be forgotten, but the recognition of price volatility is not. Most operators have launched improvement programs to sustain operations at significantly lower crude prices. Many have also made significant changes to their operational and IT organizations to drive transformation. I regularly meet new “CDO’s” (Chief Digital Officers) in both national and international oil and gas companies. They may have different professional backgrounds, but their focus is still the same, to leverage new technology to drive enterprise wide improvement in the convergence of Operational Technology and Information Technology. The CDO organizations have a high business impact potential as catalysts and drivers of change. Their understanding of operational business challenges is more important than in-depth technical expertise as they develop their organizations digital strategy, capabilities and roadmaps of improvement initiatives.

Digital roadmaps Most roadmaps include plans to improve core areas, such as Exploration, Well Delivery, Field Development, Operations and Improved Recovery. Common technology themes in the roadmaps are “AI” (Artificial Intelligence) to gain new insight, use of increasing volumes of “Big Data” from new data sources and ways to support decision-making in “real time”. The business challenges may be old, but the technical approaches to address them are challenging the organizations existing capabilities.

6 | MED OIL & GAS | October 2018

Other, faster moving industries, have demonstrated how AI allows for new and more timely insight from analyzing Real Time data. Examples may be aviation, monitoring aircraft engines, or utility analyzing windmill turbines. The digitization of virtually all equipment, “IOT” (Internet of Things) has transformed our data reality. An offshore oil platform may have more than 80.000 sensors continuously generating data. A drilling operation may generate more than 2 TB of data per day – from a single well. The potential for new operational insight is infinite, but there are also emerging concerns. Will new technology, and the way we implement it, also introduce new risks we need to address?

Learning” and “Cognitive Analytics” may sound impressive, but does not mean that the resulting recommendations or hypothesizes should be trusted blindly. A system of insight should not be a “Black-Box”. Users should always be able to see the “evidence” behind a recommendation, down to the sources of data used in analysis – as a logical audit trail. Imbedding these capabilities in systems will create a foundation of trust, and allow systems to “Augment Intelligence” rather than be considered Artificial Intelligence.

Digitalization requires thoughtful consideration The Norwegian Petroleum Safety Authorities recently published a “report on the HSE effects of digitalization” which is a valuable contribution to the awareness of challenges we need to consider. The report highlights key aspects which will be critical to succeed, and to avoid costly mistakes. One recommendation which should be obvious, but is often understated, is to involve those directly affected by change. It may be the people on the rig floor, specialists and unions. As we are evaluating new technology and ways to improve decision-making, the disciplines explicit and tacit knowledge will help ensure the quality and reliability of new concepts. A word of caution is also raised in the report, as we embrace new advanced analytics solutions to derive insight. Concepts and terminology such as “Machine

HSE strikes back While there are good reasons to advice caution when embracing new technology, there are similarly good reasons to explore how new technology can address key challenges faced by Health, Safety and Environmental professionals. In the last year I have seen major operators put HSE on their digital agenda, on par with the core value-chain ambitions. It is interesting to see how technologies which may appear as a threat can transform how HSE professionals work and can interact with operations. Some recent and ongoing examples may illustrate.

Challenge assumptions HSE professionals are facing a continuous challenge to prioritize their time and attention. Concerns related to major accidents, the working environment, emergency preparedness, security issues and the natural environment will compete for the organizations resources. How these resources are allocated may depend on several aspects, such as recent incidents and inspections. HSE professionals will naturally also rely on their own experience when planning and allocating investments. Relevant questions are whether our experience can be verified in our data or perhaps missing precursors to the next event because we are blinded by biases. One flavor of AI is the analytical capabilities to understand make sense of data represented as “natural language”. In an HSE context this may be the observations, notifications, incidents, bulletins and studies which are written by people, for other people to read. This data may appear as unstructured to traditional analytics technology, but is the target of new Cognitive Analytics or Natural Language Processing (NLP). While HSE applications are designed to capture free-text observations, they have had limited success in analyzing it for the insight reported it may contain.

may be the differentiators between facilities, teams and suppliers with varying performance and trends? Improving the safety performance has been a key driver for innovative operators. A leading example is Woodside, who continue to explore new ways to analyze their HSE data, and has twice received the Australian Petroleum Production & Exploration Association Safety Excellence Award for their achievements.

Predictive indicators in HSE Data As outlined above, leading industries are improving their ability to monitor real-time equipment data to detect “signatures” of anomalies which can impact the integrity of a facility or a process. Applying AI type Machine Learning concepts on HSE data has been a vision for HSE professionals and data scientists. In recent projects we have succeeded with new analytics approaches on the same unstructured text we used to discover new insight in the examples above. It is a very different AI data science approach, but with a high potential to detect “leading HSE indicators” which can allow organizations to prepare and address situations with increasing probability of incidents. Improving the precision of HSE analytics models, combined with additional data

sources will enable organizations to act with purpose and appropriate escalation when and where increased severity is predicted. Helping people make better decisions by new insight may be considered “Augmented Intelligence”. It may be a more appropriate description than “Artificial Intelligence” which may imply that decisions are made by the technology, and not the users.

Operational Integrity The above insight from HSE data may also add a new dimension of insight as operators are trying to get a better real-time awareness of a facility condition and integrity. As facilities are increasingly equipped with sensors and connected to operations centers, various disciplines can get continuous data feed from equipment, systems and processes. Gathering and visualizing real-time data on a 3D Model can appear as a living “digital twins” of facilities, where layers of insight can be added. HSE is a natural perspective in this context. Superimposing dangerous areas, or high risk activities may be extremely relevant information during Production Operations planning. A holistic operational view should go beyond the hardware, and communicate conditions, history and risk in the context of scheduled activities and the teams engaged.

Data-mining has been attempted, without significant success. The “AI challenge” is to understand the concepts and insight within free text observations. This requires understanding of industry terminology and how people may describe similar topics differently. Understanding context and ambiguity is key to discover new insight or test a hypothesis. Understanding root causes has always been central to continuous improvement. In HSE terms it may be interesting to understand the impact of HSE initiatives. Does the time and frequency of training matter, and what 7

Safer workplace As we are monitoring the conditions of equipment and systems, it is a natural next step to consider opportunities to safeguard the individual worker. The oil and gas industry still has a way to go to ensure the health and safety of individuals. Other industries are already innovating and deploying concepts to protect workers in dangerous environments, using proven technical building blocks. Historical location devices (People On Board tags) lacks the capabilities to communicate the condition of employees. Several devices are available to detect the environmental conditions employees are facing, such as temperature and pressure. Adding body condition, such as temperature, heart-rate and movement will combined allow us to create and customize protective shields for individuals. Solutions such as IBM IoT Safer Workplace enables shields which take into consideration the health, age and how-do-I feel-today information as well as the activities to be carried out during a shift, night or day, all seasons and weather conditions. Alerts in real-time can prevent injury, and predictive models may help define severity level and recommend next best actions – which can trigger appropriate response workflows.

Weather Operations dashboard Any preparation for safe operations must take weather conditions into considerations. The increasing resolution of information from equipment is also matched by increased granularity of weather data. The Weather Company Operations Dashboard provides real-time insight from thousands of global sensory devices. Data capture may

come from major weather, private systems, consumer smartphone devices, aircrafts and buoys at sea. Combined they provide current conditions, predictions as well as history down to areas of producing oil fields. Operators may add own equipment, such as weather radars, to get a more complete picture in areas with low coverage. The Operations Dashboard allows users to see conditions that may affect their operations. For a drilling operation it may be wind, direction, wave height, frequency and length which determines the operational window. Virtually every operation will have environmental parameters that influences risk and safety, and the intention behind the solution is to offer users an easy to customize portable interface.

may not be the technology itself, but the lack of a holistic plan to “crawl, walk, and then run” towards the vision of digitally improved safe operations. A couple of lessons learned when planning this journey is to first pay attention to the basics – accessing and managing the data you will depend on. Trust in data, in many forms, will allow for discovery, which is the second lesson learned. Select and focus on an open, scalable platform that can take your data in all the directions discussed in this article. The differentiating insight may be found in the intersection of structured and unstructured data, and you need the capability to generate value from every bit of your data.

See the big picture, and act on it As organizations continue to explore new technology, and initiate Proof of Concepts or Pilots, they will experience both successes and failures – but hopefully learn, endure and improve. The biggest threat to success About the Author

Ole Evensen is Global Upstream Strategy Leader in IBM Chemicals & Petroleum unit. He has more than 25 years international experience from working with Oil & Gas Operators and Services companies. As a consulting partner Ole Evensen has served National and International Oil Companies in Europe, Middle East, USA, Africa and Asia as strategic advisor and program manager for core E&P operational improvement initiatives. His current focus is to improve E&P operational decision-making, utilizing new cognitive, advanced analytics and IOT technology. His academic background is Advanced Management from Harvard Business School, MBA degree from Henley Management College and a bachelor’s Degree from University of Stavanger. He can be reached at ole.evensen@no.ibm.com 8 | MED OIL & GAS | October 2018

Klausdorfer Weg 163 | 24148 Kiel | Germany Tel. +49 (0) 431 6 6111-0 | Fax -28 info@podszuck.eu | www.podszuck.eu 9

In the next few years, the offshore industry expects to drill an increasing number of oil reservoirs that will require a new class of equipment designed to withstand the rigours of high pressure, high temperature (HPHT) extraction. With very little ‘easy’ oil left to discover and extract, energy companies are having to drill reservoirs that are deeper and further offshore, where temperatures and pressures exceed the 350°F and 15,000 PSI conditions for which there are global standards and regulations to govern the equipment they use.

As with any new technology being developed, a new technology qualification process should be implemented. Well operators, original equipment manufacturers (OEMs), design houses and testing labs all take part in the complex qualification process, which has several different levels in which technology readiness has to be proved.

As this is new technology, there are no global and regional regulation and standards governing the manufacture of HPHT equipment and com¬pon¬ents, therefore oil companies and their contractors face consider¬able challenges in ensuring the opera¬tional risks are managed as they drill deeper and deeper to reach the remaining reserves.

In simple terms, the first stage assigns the functional specifications, which define what the operator of the field wants the equipment to do; how it is meant to function, its operational requirements and characteristics.

10 | MED OIL & GAS | October 2018

OEMs develop the technical specifications to be used in the development of the de-

sign, ultimately creating something that will achieve the functional requirements. During the product development phase, the design also goes through risk-and-reliability studies, failure modes identification and a process of material selection. One of the challenges in creating HPHT equipment is finding the appropriate material; that is suitable to the application, resistant to corrosion and which better cope with the higher temperatures and pressures found at the drilling sites. The key to designing equipment and components that are fit for purpose in an HPHT environment often lies in the materials. Once the design is completed, the next step is to build a prototype, the testing of which validates the design. Prototypes are thoroughly tested during the validation process to confirm that all conditions anticipated in the design have been simulated and the test results were satisfactory.

Focusing on the US The U.S. standards for drilling equipment are set by the American Petroleum Institute (API). To confirm consensus from its mem-

bers, it may take a while until specific standards are developed and published by API. In the interim, the end-users of HPHT equipment lack the traditional system of quality assurance which is based on the direct application of an existing and proven standard. The industry began talking about the challenges of HPHT reservoirs some time ago. In U.S. territorial waters, the Bureau of Safety and Environmental Enforcement (BSEE) has offered guidelines for any new technology built for the harsher conditions of HPHT reservoirs. With industry ready for the extraction of HPHT reservoirs, new equipment, materials and components are being developed in accordance with BSSE guidelines in the U.S. and I3Ps, such as ABS, are playing an important role in verifying the NTQ process. This role requires everything from deep knowledge of the first principles of engineering to end-to-end experience with the processes and materials in the equipment design and manufacturing process. Specific I3P competencies for HPHT certification include understanding design features, and recognizing that design changes are possible and re-evaluation may be required. It also includes experience with manufacturing processes, working knowledge of failure modes, and familiarity with testing regimes. To help ensure the NTQ process is aligned with BSSE guidance, I3Ps verify the fabrication procedure proposed by the OEMs. Each time that changes, even for ‘enhancements’ such as product optimisation or production streamlining, the original technology qualification can be invalidated and should be re-verified. At present, the equipment manufacturer – or the contractors they often rely on for components and materials – needs to revisit the original NTQ when specifications are modified; for example, to suit the specific conditions of the manufacturing environment or in case of a change in materials. This is all then verified and validated by the I3P. However, past the NTQ phase when the I3P is no longer engaged and the equipment is moving into production, there is not a mechanism that allows the confirmation that modifications made to any of these items maintain the equipment within the boundaries of the original design. When there is a standard, they typically ad-

dress these boundaries and provides latitude to what is required to be done to maintain the equipment within verified limits, as well as offer repeatability and consistency. The difference between the qualified design, or a prototype, and what comes out of the factory, where production quality is influenced by the availability of materials, varying welding procedures, fabrication methods, etc., must be monitored to ensure the safety of the produced equipment. As such, there is a clear need for production processes to be certified and, when modified, for the original qualifica¬tion to be re-reviewed to ensure the continued compliance and suitability of modified equipment and/or processes. Although the drilling contractors are the predominant buyers of HPHT equipment, the responsibility for the oil field lies with the company that signs the lease with the regulator. So, ultimately, it is the lease-holder and regulator who need assurance that the equipment is functioning according to specification, and that any fabrication or modification remains in line with the safety requirements and good engineering practices. There are many challenges to achieving this without standards or regulatory guidance. The good news is that classification societies such as ABS are qualified to maintain a certification process and already have the systems and resources in place to do so. On a fundamental level, certification needs to help assess whether the fabrication process can support the consistent production of the kind of quality components that are required by a high-risk activity such as deepsea drilling. Founded on the NTQ principles, one of certification’s goals is to ensure that the manu¬facturer repeats the same design and production procedures for every component. Another challenge is, once the equipment is manufactured the certification process must be able to confirm that new components are inter¬changeable. .This is especially important for spare parts and replacement parts. So the certifier needs to provide a global system of traceability that is transparent and accessible to all stakeholders. Companies need to be able to trace issues such as how equip¬ment and components have been used, where they were certified

or qualified and what material was used. This track record helps the purchaser to know what they are buying. Since the users operate globally, a global system of traceability can help to assert whether the original certification remains valid, and to ensure any information or documentation is available wherever and whenever it is required. HPHT certification requires experienced, qualified engineers with deep knowledge of design fundamentals and the technological and analytical tools to support them. The NTQ process may have accepted all elements of the final design, but customization and material optimization make changes inevitable, so certification teams need an under¬standing of the design and fabrication processes and features. Certification teams also need a working knowledge of the failure modes that equipment go through to identify potential issues during the design and testing, and a familiarity with the testing regimes themselves. Evaluating whether equipment adheres to certain sound engineering principles is more involved than simply checking the test results for any modification. And because certification requires knowledge of manufacturing processes and materials, Classification societies are the best entities to execute the process. At the end of day, the goal is to ensure that the equipment is produced in a sound manner that will be safe to operate. process. Until standards and regulations are created, the technical rationale that was approved during technology qualification process is the best path to assessing product quality and safety.

Author

Luiz Feijo Director Global Offshore Production, ABS

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Presight Dynamic Barrier Monitoring Software – increased awareness of barrier status and major accident risk across offshore operations A successful barrier management process with monitoring of barrier status that makes information easily accessible will ensure a better overview of the risk, better assessments, better decisions and thus an improved safety level. COMPANY HISTORY Presight Solutions is a Norwegian Software development company located in Stavanger. The software Presight Barrier Monitor (BM) helps our customers to get a better awareness of the barrier status and understanding of the current risk situation in offshore operations by using ‘live’ or dynamic data. The aim of Presight BM is to provide companies with leading barrier performance indicators for crew and management in decision-making situations. Presight BM was born out of a contract with Norwegian operator Norsk Hydro which wanted to use its current data as a basis to make safety decisions, not relying on historic data.

Barrier monitoring in the oil and gas industry From the first discovery of oil on the Norwegian Continental Shelf in 1967 until today, there has been a tremendous development in the way the industry work to ensure a high safety level. The work regarding safety for the past 50 years has been aimed at avoiding major accidents. Behind such accidents, a complex causal relationship between individuals, organisation and technology is often found. The accidents are usually a result of a chain of decisions on 14 | MED OIL & GAS | October 2018

many levels. To prevent and limit the extent of possible accidents, both technical, operational and organisational barriers need to be built into the design and into the way the assets are operated. Today, the Petroleum Safety Authority (PSA) in Norway requires that the party responsible for the operation of an offshore facility shall stipulate the strategies and principles that form the basis for design, use and maintenance of barriers, so that the barriers’ function is safeguarded throughout the offshore facility’s life. In addition, personnel shall be aware of what barriers have been established and which function they are intended to fulfil, as well as what performance requirements have been defined in respect of the concrete technical, operational or organisational barrier elements necessary for the individual barrier to be effective. Personnel shall also be aware of which barriers and barrier elements are not functioning or have been impaired. Necessary measures shall be implemented to remedy or compensate for missing or impaired barriers (The Management Regulations §5). UK, US and Brazil have similar requirements as Norway.

Companies investments in barrier monitoring Continuously monitoring of the barrier status on an installation will give a quick overview of which barriers are functioning and which have been impaired. Various companies have different motivation or intention for their investments in barrier monitoring software. Some companies implement the solution only to fulfil the regulatory requirement of being aware of degraded barriers,

and the solution is anchored and used mainly by the HSE department. Other companies use the software solution to document that they keep control of the status of their barriers towards clients and operators. However, the majority use the solution because they want to operate safe and efficient. This is ensured by getting access to updated information for decision support and planning. In these companies, the solution is anchored and used by most personnel at the different level of the company, from operators offshore till top level management.

Terminological confusion Different interpretation of the barrier concept and how to apply it has prevailed in the Norwegian petroleum industry ever since the term ‘barriers’ was introduced into the regulations in 2001-2002. Companies have different understanding of what the term means, and how barrier requirements are to be complied with. It seems that there are no unified philosophy and understanding of the term, and even the definitions varies. The newest edition of the barrier memorandum issued by PSA in 2017 provides a clearer explanation of the term barrier, and describes in better terms the interaction between technical, organizational and operational barrier elements. The question ‘Who does what with which equipment in failure, hazard and accident situations?’ describes the interaction between the barrier elements. The question also clarifies what is necessary for realizing a barrier function.

Presight Barrier Monitor Presight BM is a fully configurable solution, and all our clients run the same software.

Figure 1: Illustration of a barrier function, and how it can be realized (Source: PSA, 2017)

Implementing Presight BM forces a process of systematically reviewing previous work regarding barrier management, documentation, work processes, internal routines, risk assessments and various data systems. The implementation phase may give several improvements such as compliancy with rules and regulations, improved work processes, consistent definitions and ensuring good quality and treatment of data.

When configuring the software, relevant barrier indicators are established. Usually design documentation are used as a basis for this. The documentation is often published from different perspectives such as strategy documents, performance standards, MAHs/DHSAs and work processes. The indicators are structured and aggregated in different ways to ensure a holistic approach that can illustrate barrier status in various ways, such as per system, per area, per operation etc. The indicators are given a colour code (green, yellow and red signals), based on status compared to target and acceptance values. Various dashboards communicate the barrier status in different ways. Examples are management dashboards, OIM dashboards, operational dashboards and dynamic bowtie visualisation. The purpose is to give the necessary information to the right personnel for better, safer and more efficient decision making.

work with barrier management. The Norwegian legislative regulations do not specify in detail how equipment shall be designed, or how work operations shall be performed. The requirements are function-based, which describes what safety targets or functions needs to be fulfilled. This means that the companies have different approaches to solving the same objective, and they have great freedom to choose their solutions. The understanding of the requirements varies from company to company, and the maturity level in the industry is uneven. Some companies have done an extensive job, and worked well and structured with barrier management, while others are still struggling to implement the requirements.

Another area of improvement is the consistency and structure of the relevant data in the source systems. Certificates, courses, competencies, inspections, equipment and processes should be organized in such a way that it is accessible for monitoring by Presight BM. System improvements are often identified, and workarounds are required to reformat the data. The goal is to make most information system-driven and automatic to remove the need for manual data entry. The implementation phase will also lead to an increased focus on barrier management and risk awareness throughout the organization as the implementation process requires attention from personnel at various levels in the organization. After implementing the relevant barrier element indicators in Presight BM, performance of each indicator will be monitored. In the implementation phase, we look for all

Figure 2: Dashboard illustrating barrier status in Presight BM

Presight BM is used in operational planning (management of inhibits, permit to work approvals, strategic planning (input to senior management planning), maintenance planning (planning and prioritization), risk and barrier awareness communication, platform management morning meetings, handovers etc.

Lessons learned during the implementation phase Among our clients, even though they operate in the same legislative regime and towards the same operators, we have seen various approaches in their 15

Figure 3: Dynamic bowtie visualization in Presight BM

measurements that can give an indication of the barrier status, also known as performance influencing factors. Presight BM retrieves data from digital systems (source systems) to be able to indicate the status of the barrier elements. Examples of systems are maintenance systems, competence matrixes, HR/resource planning systems, documentation, training, inspections, drills, risk assessments, PtW, condition monitoring systems, inhibits and isolation logs, etc.

HSE awareness in operation How do people, both on the installation and onshore, know that the barrier elements are in place, that they are functioning as they should and that they will work when they are needed? Information needs to be actively seeked to be able to understand the barrier functions to manage the operation in a safe manner. It is important that people need to understand the risk involved, know the barrier functions, why they are in place and, most importantly, that people understand their own role as part of the barrier function. Presight BM ensures that this information is communicated in an easy and understandable way. The information is communicated on a high level, with easy drilldown to the details on the lowest level. In the implementation phase, great attention is given on risk and barrier management which will increase risk awareness on several levels in the organization. In operation, Presight BM is used regularly in daily meetings, such as the OIM morning meeting and PtW meetings. The software is a part of the decision support basis that ensures HSE awareness throughout the organization. 16 | MED OIL & GAS | October 2018

Continuous improvement As seen while implementing Presight BM, a review process is forced, which may lead to several improvements. In addition, information regarding the barrier status is used for prioritization of tasks and planning of work. Presight BM will help reveal which barrier elements or functions are most critical, as elements that are involved in several barrier functions and barrier functions that are necessary to prevent several DSHAs from occurring might be more critical than others. When this is known, measures and tasks may be initiated to ensure that the barriers are maintained in the best possible way. By structuring the overall status over time, trends can be monitored, which can contribute to prioritize the correct measures and tasks to ensure continuous improvement. Presight Solutions also arrange workshops and client meetings for all our clients. This ensures that experiences are shared across the different companies which will create a basis for learning. In addition, continuous improvements in the Presight BM software is ensured by issuing software releases 1-2 times a year to include new functionality and features based on input from clients.

New technologies give new possibilities Now, Presight Solutions is building the next generation barrier monitoring software. By using VR and AR as visualization methods, additional information may be added to the â&#x20AC;&#x2DC;realâ&#x20AC;&#x2122; barrier components which can reduce the risk while performing maintenance or modification tasks as more information be-

comes available. In addition, it will be easier with remote expert assistance and information sharing between onshore and offshore personnel and partners. Today, Presight BM can predict or forecast the barrier status based on planned operation (maintenance or modification tasks), planned manning/rotation and weather forecasts. By using new technology, such as machine learning, technical aspects, such as prediction of equipment failure might be included to further increase the quality of the forecasts.

Author

Lene BjĂ¸rnsen Risk and barrier management advisor in Presight Solutions.

Geosteering CTD using the drill bit as a sensor The precise depth at which a target formation will be penetrated by the bit is never known with certainty until the well is actually drilled. Yet maximising recoverable reserves depends on optimal wellbore placement, which in turn depends on reacting to the newly confirmed knowledge of a formation boundary’s whereabouts the moment it is discovered. A new technology, RockSenseSM, provides at-bit bed boundary identification while Coiled Tubing Drilling and gives engineers and directional drillers as new tool in the Geosteering toolkit.

of Energy expended per foot of hole drilled and would therefore have a relative indicator of the changes in formation being drilled. In this fashion, by continually monitoring torque, WOB, pressure and ROP, AnTech’s RockSenseSM provides information about the formation being drilled, as drilling proceeds. The high data rate offered by wired telemetry, permits multiple measurements to be made per foot of hole drilled, yielding inch level resolution in the processed signal.

Highlighting the need for a new Geosteering method Setting the scene Mechanical Specific Energy was first proposed by Teale in 1965. MSE provides a way to characterise the energy required to drill a length of hole in a formation. It follows that, as the drill-ability of the formation changes, so does the energy required to drill it. It turns out that a plot of MSE vs Depth for a section of hole is a very good proxy for porosity, and the fact that it is an at-bit measurement makes it an extremely useful tool to have when navigating vertically limited formations. The calculation of MSE requires real time measurement of Weight-on-Bit (WOB) and Torque. Historically, downhole Weight-onBit and Torque were derived from surface measurements, with corrections applied for the effects of buoyancy and friction. The error inherent in these empirical corrections was usually greater than the signal in the subtle changes in MSE due to differing formation characteristics. In other words, the signal from the formation was lost in the noise of the corrections. Latterly, technology advances have permitted downhole measurement of WOB and Torque, but mud pulse bandwidth limitations have imposed severe constraints on the definition that has been possible. The latest generation of Coiled Tubing Drilling BHAs, featuring integrated downhole sensors and high speed wired telemetry, provide a technology platform that finally makes high definition MSE measurements possible,

opening a new window on the downhole environment as drilling progresses. The technology has sound, intuitive footings. Picture yourself a passenger in a moving car. Even with your eyes closed, you know the type of road you’re travelling on (freeway, city street, dirt road) by the road noise you can hear. Anyone who has ever drilled a hole in a masonry wall to hang a picture, or fit shelves will have experienced the principle at first hand. Without even thinking about it, the person holding the drill is aware when he is drilling the plaster, when he is drilling brickwork and when / if he hits a void in the brickwork. Consider now a motor turning a drill bit which drills a hole in a sample of rock. We can measure the power input to the motor as the hole is drilled to gain an understanding of the type of rock we’re drilling. If it was an electric motor we would simply measure the voltage applied and the current flowing during drilling and multiply them to get the instantaneous power. For a positive displacement mud motor it’s slightly more complicated, but it can be done. If differential pressure and flow rate can be measured then, given knowledge of principal operating constants for the motor, an expression for power in terms of pressure and flow rate can be written. If we were then to integrate this power as the hole progresses we would have a value

Look at figures 1a and 1b. Based on formation tops observed in previously drilled vertical wells, a horizontal side-track is planned based on a casing exit depth, a build rate that will land the lateral the required distance below the top of the reservoir and a target inclination which will track the top of the reservoir. A modern directional Coiled Tubing Drilling BHA will be able to feed directional information (inclination and azimuth) to the surface as drilling proceeds which can be combined with bit depth to provide an accurate estimation of the borehole’s position in 3D space. But if the top of the reservoir formation is not flat – more like that in figure 1b, then navigation by dead reckoning alone will land you in the seal, not the reservoir. The solution to this problem is the well-established art of Geosteering. Geosteering is the practice of directing the borehole in response to observed characteristics of the formation. Sensors, such as gamma, resistivity, porosity are available to measure distinguishing characteristics of the formation. Although these sensors are mature, with good reliability and consistent performance, a significant feature which affects their use in Geosteering is the position of the sensor along the BHA. The BHA is constrained by its nature to be a long thin tube. Maybe 3 inches in diameter and many tens of feet long. At the bottom of the BHA is the bit. 17

Figure 1a. Planned side-track well based on linear interpolation between formation tops.

Immediately above the bit, by necessity, is the mud motor, occupying 10-15 ft of BHA length, and the directional sensor package is normally located immediately above the BHA. This means that sensors sensitive to identifying characteristics of the formation are constrained to be at least 20 â&#x20AC;&#x201C; 25 ft behind the bit. The significance of this in Geosteering terms is illustrated in figures 2a and 2b. A change in formation characteristic is not visible to the sensor until 20-25 ft of hole has been drilled in the formation. As figure 2 illustrates, this implies a corresponding delay in informed steering decisions, with the consequence that the formation of interest may be exited before a steering correction can be made. If the additional vertical depth traversed during the delayed steering correction happens to be water bearing, the negative impact on lifetime productivity of the well can be significant. Even if there is no productivity impact, time spent drilling unproductive formation will impact the projectâ&#x20AC;&#x2122;s bottom line. As figure 2b illustrates, the ability to make a steering decision at the time that the bit penetrates the formation results in a much better chance of staying within the target formation. Geosteering can also be informed by analysis of cuttings. The time taken to circulate cuttings to surface, capture them and prepare them for analysis means a delay, similar to that described above occurs between the time the bit penetrates a formation of interest and the time it is confirmed by cuttings analysis. The bit continues turn during this time, meaning that, once again, the formation of interest is substantially penetrated before positive confirmation is received at surface, reducing the TVD available to successfully complete a steering action. Dispersion of cuttings in the annulus (different sizes and densities travel at different speeds) can also adversely affect depth resolution. 18 | MED OIL & GAS | October 2018

Figure 1b. Actual side-track well misses formation due to a non-linear formation top depth between the vertical wells.

Exploring the solution in practice Having illustrated the case for at-bit bed boundary identification, and described its embodiment in RockSenseSM, letâ&#x20AC;&#x2122;s see it in practice. Although RockSenseSM is available as a real time service, to inform navigation decisions while a well is being drilled, the system works just as well with historical data sets. Two data sets have been chosen for analysis, based on the availability of conventional logs from adjacent wellbores for corroboration. The first data set is from a Coiled Tubing Drilled side-track of a well in North America. The well was in a densely drilled locality and open hole logs for nearby vertical wells were made available.

crease production through increasing reservoir contact. The operator used 3D seismic to evaluate the formations and identified a subsurface ridge that could be acting as a trap. The well path was planned to pass approximately 15ft below the formation top and track the formation by holding inclination. The oil water contact was believed to be 40ft below the formation top and, if it was entered, would significantly impact the well economics. Gamma ray sensors were used for depth correlation because relying on seismic depth alone would not provide the depth accuracy required. The hole section was drilled using single phase fluid in the build section.

No horizontal wells had been drilled in the area previously and the objective was to in-

Running the RockSenseSM software on the data gathered during this job revealed compelling similarity in the shape of the density log for nearby wells and the RockSenseSM trace when plotting porosity against TVD, as can be seen in Figure 3.

Figure 2a. Steering decision based on up tool sensor.

Figure 2b. Steering decision based on at-bit measurement allows trajectory to stay in target zone.

Figure 3. Compelling similarity between the shape of the density log for nearby wells and the RockSenseSM log when plotting both quantities against TVD. (Note that the RockSenseSM scale is offset in this view).

Figure 4. Applying RockSenseSM historically reveals its sensitivity to boundary crossings.

The second data set involves Underbalanced Coiled Tubing Drilling in a shale gas well, also in the United Sates, which is illustrated in Figure 4. In this instance, a 4-3/4” lateral was drilled using Underbalanced Coiled Tubing Drilling with a mixture of up to 40% nitrogen to minimise formation damage. It was intended that the wellbore should stay within an identified formation layer. Post processing the historical data using the RockSenseSM software clearly identifies a substantial footage drilled below the target formation. Were that lateral to be drilled today, with real time RockSenseSM on screen, a more reactive steering strategy could have been followed. In this more reactive strategy, RockSenseSM would be used to identify crossing the formation top, at which time the trajectory would be adjusted to follow the formation dip, with RockSenseSM being monitored as a guard against exiting the formation.

In summary RockSenseSM delivers an at-bit bed boundary identification service of a type not seen before. The service is delivered in real time, as the hole is drilled. It is made possible by the low latency, high rate transmission of data from high fidelity downhole sensors. The parameters measured are representative of conditions at the bit – not 25 feet behind the bit, giving the driller a 25 ft head start in making his steering decisions. This potentially disruptive service means he can deliver an optimally placed wellbore, with more feet drilled in the target zone, resulting in improved lifetime productivity, higher initial production and substantially improved project economics.

ii MSE. Teale, R.: “The Concept of Specific Energy in Rock Drilling”, Intl. J. Rock Mech. Mining Sci. (1965) 2, 57-73.

Profile Richard Stevens Richard is a Coiled Tubing Applications Engineer at AnTech and has over 17 years of industry experience, operating AnTech’s CT Drilling tools in the US, Saudi and Europe. Richard has been influential in the design and development of AnTech’s Coiled Tubing Drilling equipment and holds a Master’s Degree in Mechanical Engineering from the University of Exeter, UK.

20 | MED OIL & GAS | October 2018

SUPERSPEC SPECRIGS RIGS SUPER AND AND DIGITALIZATION DIGITALIZATION Bentec Enhanced Software Technology Bentec Enhanced Software Technology Bentec GmbH Drilling & Oilfield Systems Bentec GmbHDrilling Drillingand & Oilfield OOO Bentec Oilfield Systems Systems OOO Bentec Drilling and OilfieldCo. Systems International Drilling Technology L.L.C. International Drilling Technology Co. L.L.C. Phone: +49 (0) 5922 7280 Phone: (0) 5922 7280 E-mail:+49 sales@bentec.com E-mail: sales@bentec.com www.bentec.com/equipment www.bentec.com/equipment

Easily available as-built information accelerated LR Marineâ&#x20AC;&#x2122;s project execution tremendously.

Staying competitive in the offshore industry Even though the global price of oil per barrel has started to stabilize, the North Sea oil & gas industry faces multiple challenges in the near future. Peter van der Weijde, Hexagon PPM, talks about the ways smarter software solutions can help the oil & gas industry continue to reduce costs to remain competitive and improve asset performance. 22 | MED OIL & GAS | October 2018

As the aging North Sea basin has higher operating costs than many younger oil basins around the world, the companies operating in the North Sea must focus on efficiency and productivity to stay competitive. As one of the ways to answer to competition and improve margins, we can see that owner operators are currently looking for ways to extend the lifecycle of their existing facilities and extract the most value from these facilities while they are operational. There are many benefits when compared to building new facilities; no new capital investment is needed, the entire existing infrastructure is already in place, and plant personnel are already trained. For the engineering, procurement and construction (EPC) companies, this shift in the oil and gas industry has required a change of focus as well. As the number of greenfield projects has decreased, the key for competitive advantage for many EPCs is to be able to execute brownfield projects faster and more accurately than the competition. In a way, fewer projects and more competition have acted as a catalyst for the EPCs in the oil & gas industry to look beyond their traditional tools to find smarter ways to execute projects better.

Getting the most of existing assets Comprehensive, integrated and easy-to-use software solutions are key for improving efficiency and lowering the time needed for shutdowns and maintenance projects. Solutions such as Hexagon PPM’s CADWorx® & Analysis suite can help users to capture the existing as-built situation quickly and accurately by making use of laser scanning or laser surveying technology. Once a scan or survey is completed, team members can easily change the unintelligent captured data to intelligent 3D objects. In the case of regulatory requirements, the 3D objects can be also checked by analysis tools without the need for remodeling. If any design changes take place, these changes can be automatically reverted to the original 3D design while updating the 3D model. All deliverables like Bill of Materials, isometrics and general arrangement drawings can be then generated automatically from the 3D model. This level of integration and automation drives the productivity and quality of the design to another level and makes the engineering and fabrication processes very competitive.

Real-life project example: Norwegian crude oil tanker LR Marine A/S, a total supplier of cost efficient, effective and sustainable solutions for marine and industrial applications, was hired to route and install a piping connection for a VOC (volatile organic compound) recovery system on a Norwegian crude oil tanker. The project scope included executing a laser survey on the existing vessel to ensure that the new equipment would fit into the existing piping. One of the main challenges during the project was the necessity to ensure the new VOC recovery system would fit into the existing piping, guaranteeing there would be enough space available for the installation and welding. An additional challenge was the ability to ensure the accuracy of the design for the new equipment: the ship was in the United Kingdom whilst the fabrication work took place in Northern Germany. This meant that revisiting the vessel for rechecking information would have cost LR Marine a significant amount of time, slowing down the overall project execution. To ensure that the new equipment would fit, LR Marine chose to execute a laser survey of the deck and the piping of the vessel with the help of Leica Total Station, and to use CADWorx Plant Professional for the 3D design of the new piping.

Realizing Results First, LR Marine boarded the ship in Liverpool. LR Marine used Leica Total Station to 3D scan all the piping and equipment on the deck, which took only one day. Afterwards, Leica engineers converted the point cloud data into a readable file, which LR Marine converted into a CADWorx file (.dwg format). By using CADWorx Plant Professional, LR Marine were able to determine and create an exact and accurate design of the VOC new equipment. The next step was to design the new piping and the connections between the existing piping and new equipment. After fabrication was finalized, LR Marine was awarded a contract to further fabricate and insulate the new piping. The pipe spool drawings were produced based on the 3D design created in CADWorx, and this information was also used to create a cut-out

plan for fabrication. The new piping was afterward installed in the FA yard at Odense, Denmark, and the installation was done under the supervision of LR Marine. When installing the new piping, as well as requiring sufficient spacing to fit the piping into the deck, extra space for installation and welding was also needed. LR Marine’s extensive experience on similar projects combined with the accuracy of the designs created in CADWorx Plant Professional enabled the company to overcome this challenge. LR Marine is expecting similar types of piping connections for VOC recovery systems to be installed in the future for other similar vessels, and will be using Leica Total Station in combination with CADWorx Plant Professional for these projects. Soren Kjaer, sales manager at LR Marine, said “This type of combination of Leica and CADWorx offers a unique capability to have access to as-built information anywhere in the globe. It enabled us to improve efficiency and deliver our customer high quality and accurate results in a record time.” For more information, please visit www.hexagonppm.com.

CASE STUDY FACTS AT A GLANCE Company: LR Marine Website: www.lrmarine.dk Description: LR Marine A/S is a total supplier of cost efficient, effective and sustainable solutions for marine and industrial applications. LR Marine’s core business and primary activities are within the fields of pre-insulated pipe systems, machinery units / skids and cryogenic cargo tank insulation. Employees: 55 Industry: Marine Country: Denmark PRODUCTS USED: • CADWorx® Plant Professional • CAESAR II® KEY BENEFITS: • Ability to access as-built data no matter of physical location. • Ability to ensure accuracy

24 | MED OIL & GAS | October 2018

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26 | MED OIL & GAS | October 2018

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CASE STUDY

Dudgeon Offshore Wind Farm Remote Cathodic Protection Monitoring System INTRODUCTION Due to the global drive to move away from the use of fossil fuels for energy production, successive British governments have worked to increase the proportion of renewable sources into the energy mix. Renewable sources of energy have gone from 2.5% in 1990 to almost 20% in 2014, with the large proportion of this coming from both onshore and offshore wind farms (9.4%). The UK is considered as one of the best locations for wind energy production in Europe and rapid increases in capacity are in progress, with more planned. lnstalling and operating offshore wind farms is presenting the industry with numerous challenges to ensuring that the wind turbine generators remain protected externally from corrosion throughout their design lives. Traditionally, steel structures are protected from corrosion subsea by sacrificial anodes arranged evenly around the surface area. However, the monopile design of wind turbines means that a bank of anodes mounted near the surface must provide protection all the way down to the seabed. Fast-flowing water in the areas where the wind farms

The Njord service operation vessel (SOV), used as the deployment vessel for the project. The jack up vessel Sea Challenger can be seen carrying out operations on the offshore transformer station in the background.

28 | MED OIL & GAS | October 2018

are built reduced the effectiveness of the cathodic protection (CP). As future construction is foreseen out into deeper waters, these problems could be compounded. Due to the dynamic environment, it is difficult to ensure that the external CP systems on these unmanned structures are operating effectively- however it also makes it more important to do so. The high water flow makes installing fixed sensors for any length of time very difficult , and the cost of repeated site visits by technicians to retrieve the data makes remote access the more suitable option. Using Deepwaterâ&#x20AC;&#x2122;s rugged monitering system based upon V-string reference electrodes tethered to a semi-tensioned tether system were developed and selected as a suitable solution to the requirements. Remotely accessed data log-

ging systems powered by PV solar systems were paired with this to minimise ongoing operational costs. Deployment of each of the 4 systems in their entirety took approximately 12 hours.

BACKGROUND The Dudgeon offshore wind farm (OWF) is a new development currently in construction and to be operated by Equinor ASA. Dudgeon OWF is located 32 km off the north Norfolk coast, with a stated capacity of 402 MW generated via 66 No. Siemens 6 MW wind turbine generators (WTGs). All foundations have been driven, with projected installation of the WTGs and final rock dumping during 2017 . To provide assurance that the installed external galvanic CP systems on the structures

FLXMAT concrete weight mattress and tether, prepared for deployment. The tether has been coiled in a figure-of-ei ght on the top of the mat and secured using quick-release snaps, in order to prevent snagging during deployment.

are providing the required protection, Statoil identified a need for fixed CP monitering systems to provide confirmation of adequate CP performance. Measuring and recording reliable, repeatable CP readings from fixed locations and depths in the high-flow tidal areas of the OWF is difficult, yet vital for ensuring that the anode systems are meeting their design criteria. It was planned for the monitering systems to be installed during the early stages of the field construction, so that the early CP polarisation data could be gathered and any long term seasonal variations identified and further monitored. Deepwater provided a short optioneering study to Equinor, leveraging different approaches to mounting and routing the subsea sensors to minimise risk of system failure. Communications and data integration options were also explored. The final design was chosen as the most mature of the options , being a development of previous remote monitering systems developed by Deepwater and provided to various operators. The intention with the design being to minimise any impact to the structure and operational systems of the WTG.

SCOPE OF SUPPLY Detailed design was carried out by Deepwater, utilising lessons learned from previous installations for offshore wind, and the specific requirements of the Dudgeon OWF. The requirement for data from the initial stages of the construction of the field called for a selfpowered system, which was not reliant on communication via the field SCADA network. Alterations or additions to the structure of the WTG were not possible, so all the components of the system had to be designed in such a way that they would be securely fitted to the already-installed transition piece without impeding access or operation in any way. Finally, all the monitering system was to be installed on the TP’s external work platform using topside rope access teams and with the assistance of the service operation vessel (SOV) which provides support to work scopes being carried out in the OWF- no jack-ups or subsea intervention was available. The final system design consisted of a topside unit with data logging and remote communication capabilities, for the storage and transmission of data from the 3 zinc V

string reference electrodes to be installed per structure. The monitoring and communications equipment comprised of off-theshelf (OTS) components , configured specifically to meet the project’s requirements. This provided a cost saving over a fully custom system , while still providing the ful! functionality required. The monitoring and communicat ion system was powered by a solar array with back-up battery bank. This provides reliable standalone electrical power, even during winter months due to the carefully managed power configuration optimised by Deepwater’s engineers. The subsea component comprised a weight mattress connected to the WTG above the waterline via a synthetic tether , with the CP potential electrodes attached at specific points along its length. The FLXMAT system was selected as the most suitable solution to provide the ballast; Rather than using a reusable steel mould, the concrete is cast directly into plastic shells that stay in place meaning there are no sharp edges that could damage the cable. lncidental impact damage to the TP coating during installation is also minimised, as is the potential for 29

Deployment of the concrete mattress and tether with acoustic release mechanism.

Tether hang-off position on the horizontal support of the middle rest platform. The cables from the reference electrodes were routed up the ladder to the external work platform from this point. 30 | MED OIL & GAS | October 2018

injuries due to concrete dust and particles. The tether was selected for its high breaking strain, as well as its seawater, corrosion, UV and abrasion resistance. The weight mattress and tether components were specified to withstand the high current and weather conditions expected in UK coastal regions, based upon modeiling carried out by third party design engineers . The tether was part-tensioned via an attachment to the middle rest platform of the TP, keeping the whole assembly clear for safe access of the WTG while ensuring that the reference electrodes remained at fixed points in the water column.

erence electrodes per structure was chosen, with 1 No. positioned below the level of the rock dump; 1 no. just above the rock dump layer; and 1 No. at the mid-point of the submerged section.

release systems were leveraged to remove the requirements and keep installation costs down. Rope access teams supported the topside routing and fitting of the tether tensioning system and monitering systems.

The scope was to provide 4 systems to be installed on representative WTGs throughout the field. The materials supply was completed by Deepwater EU in the UK, with the separate components consolidated and delivered to Great Yarmouth , UK in time for loading and deployment according to the project schedule .

Weather conditions were a limiting factor due to the minimal distances between the vessel, the crane, and the WTG structure. However, all elements of the installation and commissioning work scope were completed successfully and ahead of schedule.

INSTALLATION The V-string zinc reference electrode provides long-term, stable CP potential measurements and was selected for this application due to its rugged construction. The zinc reference electrode is far less fragile than a silver I silver chloride equivalent, with a longer reliable design life, both of which are advantages in dynamic environments where replacement is not envisaged. The cable tail is especially toughened and sheathed with an abrasion-resistant synthetic braid, further improving protection. A total of 3 ref-

Installation of both the topside units and the subsea components was carried out under Deepwater supervision, both on the vessel and the structure, with support from rope access technicians from Trac and the crew of the clientâ&#x20AC;&#x2122;s Service Operation Vessel (SOV), the Njord, operated by Esvagt under the control of Statoil client representatives.

Author

Timothy Britton The entire system was installed without any subsea intervention by diver or ROV; cameras attached to the crane hook and acoustic

Vice President Sales & Marketing Deepwater Corrosion Services, Inc

Topside portion of the monitoring package, with monitoring and communications enclosure (left), power control enclosure (right), battery system (black, right), and solar array (left, on outboard side of the hand rail). 31

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Legal challenges and solutions for oil, gas and pipeline developments in the eastern mediterranean INTRODUCTION TO THE LEGAL CHALLENGES The significant hydrocarbon discoveries in the Eastern Mediterranean over the past decade have highlighted the political and economic challenges of developing natural gas and transporting it to market in a volatile area of the world. These issues are of course heightened by the continuing tensions between the countries in the region, which present huge challenges to investors in petroleum projects requiring massive investment and long time periods for recovery of that investment. This article discusses how such risks can be avoided (or at least mitigated) and workable solutions found.

Managing Political risks Where there is a hydrocarbon discovery, there is an attendant risk that development could be delayed because of adverse government action or inaction. Political groups may attempt to delay the project, claiming violations of local laws, or claims of unpaid taxes or corruption. By way of example, the development of the Tamar and Leviathan fields was frozen while Israel’s Delek and its co-owner contested allegations from Israel’s antitrust commissioner of anti-competitive behaviour. Pipeline projects and the sales of production which cross international borders are

particularly vulnerable to political risk. A major discovery may tempt a host government to take a larger share of production, or even expropriate an entire project, on the grounds of national emergency or shortages of oil or gas in the host State. Other examples of adverse government action include: • delay, withholding or revocation of governmental consents necessary for the development of the oil or gas field or the construction of any pipeline; • inability to obtain rights-of-way for a pipeline due to government action (or withholding of government support); • if two or more States are involved, or if there is terrorist action, the seizure, damage or shut-down of a pipeline; • expropriation of a pipeline or pipeline segment or the company owning the pipeline by one of the host States; • government refusal to allow transfers of funds, importation of equipment, or the transfers of necessary personnel for pipeline purposes; and • military conflict or threat of military action. Political risk should be considered at the outset of a project and mitigated where possible. Such mitigation measures include having a detailed knowledge of local laws and regulations applicable to petroleum exploration and development, including investor protection laws, and a comprehensive understanding of the terms of the applicable production sharing contract, concession or licence. An investor should consider structuring investment vehicles to take advantage of the protections offered by bilateral investment treaties (BITs), where applicable. BITs pro-

vide investors with protection against the unlawful expropriation or nationalisation of their foreign investment (and other actions) by a signatory host State. Such protections include: • treatment shall be afforded to the investor and its investment that is no less favourable than that given to nationals of any other state (“most favoured nation treatment”) and the host state (“national treatment”); • the host State will ensure “fair and equitable treatment” of the investor and its investment; • the host State will not expropriate the investment without compensation; and • crucially, a means to enforce the BIT protections by giving an investor a right to bring arbitration proceedings against a host State. Managing the risk of government action in cross-border projects may involve the use of international treaties or inter-governmental agreements (IGAs) between host States. Such treaties or IGAs may oblige host States to: • provide assistance to the project and not interrupt the flow of oil or gas; • grant necessary licences and permits and ensure that its government bodies act without delay; • take all necessary measures to avoid operational difficulty and delays to the project; • permit companies involved in the project to transfer hard currency into/out of the States in question, to maintain accounts and exchange currency at market rates; 35

• not discriminate against the project in favour of other projects; • ensure the safety of project assets and personnel in its territory; and • permit free movement of project personnel and import and export of project assets into/out of its territory.

Maritime boundary disputes The discovery of potentially game-changing hydrocarbon reserves in the Eastern Mediterranean has exacerbated decades-old maritime border disputes and led to new inter-State tensions. For investors in the region, such tensions can have very real consequences for exploration and exploitation and adversely impact options for natural gas export. Cyprus and Turkey The disputed maritime border between Cyprus, Turkey and the Turkish Republic of Northern Cyprus (TRNC) has impacted the operations of oil and gas companies in the region. The northern portion of Cyprus’ block 6 is located on the continental shelf claimed by Turkey. In 2011, Turkey awarded rights to a block overlapping Cyprus’ block 3 to Turkey’s national oil company, TPAO. Turkey has moved to block and disrupt the operations of Italian multinational E&P company Eni in the disputed area; in February 2018 Turkish naval forces prevented an Eni-chartered Saipem drill ship from conducting exploration work between Cypriot blocks 6 and 9. Turkey also rejects all agreements entered into between Cyprus and Egypt, including a 2003 maritime demarcation agreement, a 2012 cooperation agreement in respect of exploration on the Egyptian-Cypriot border, and a 2013 international convention on the joint exploitation of hydrocarbon reserved on the median line between the two States’ respective exclusive economic zones. In 2012 Turkey indicated that it might review the Turkey-based investments of any company exploring for hydrocarbons in disputed Cypriot waters (a threat which has not, as yet, been carried out). Such political challenges have a very real impact: for example, Cyprus’ Aphrodite gas field remains undeveloped following its discovery in 2011 – a consequence of several factors, one of which is the Cyprus-Turkey maritime dispute. Israel and Lebanon In 2010 Israel and Cyprus signed a maritime border agreement – denounced by Lebanon which alleged it encroached on its exclusive economic zone. Those coordinates were 36 | MED OIL & GAS | October 2018

submitted by Israel to the UN in July 2011. Lebanon conducted its first licensing round in 2017, awarding two blocks to a Total-led consortium. Israel warned the consortium over undertaking activities in Lebanon’s block 9, which includes disputed waters between Israel and Lebanon. Hezbollah has threatened to attack Israeli offshore installations if Israel attempts to disrupt Lebanese exploration. Total, as a compromise, has stated that the consortium will drill no further than 25 km from the disputed border. Natural gas export options Maritime disputes also impact on the three main options for Cyprus, Israel and Lebanon to export and monetise their gas reserves to the maximum degree: (i) via the existing pipeline from Israel to Egypt, and Egypt’s existing LNG facilities; (ii) via a pipeline link to Turkey; or (iii) via a new pipeline to Europe. • Egyptian LNG - Using the existing natural gas pipeline between El Arish, Egypt and Ashqelon, Israel to deliver gas to Egypt’s underutilised LNG export terminals, Damietta and Idku, would avoid the cost to Cyprus and Israel of constructing and operating their own LNG terminals. The latest announcements from Delek indicate that gas from the Tamar and Leviathan Fields may be sold to the Egyptian company, Dolphinus Holdings. While these announcements are promising, the arbitration dispute between Israeli and Egyptian companies as a result of the termination of the Israeli-Egyptian gas deal in 2012 will need to be resolved. Another possible participant in the equation is Cyprus; Egypt and Cyprus signed an IGA in 2016, allowing producers at the Aphrodite field to use Egyptian infrastructure for exports. If existing obstacles can be overcome, the prospect of Israel and Cyprus (and possibly even Lebanon in the future) tying-in to Egyptian export facilities could create a regional energy hub, with wider export options – notably, the Suez canal would allow tankers to ship LNG to both European and Asian markets. • A pipeline to Turkey - A link to Turkey would be politically difficult, transiting through either Cypriot, Lebanese or Syrian waters. Cyprus would be likely to resist any attempt to construct such a pipeline, so long as Turkey contin-

ues to disrupt its exploration efforts. Arab-Israeli hostilities would preclude any route through Lebanese or Syrian waters. • EastMed – The proposed Eastern Mediterranean (EastMed) offshore/onshore pipeline, connecting East Mediterranean resources to Greece via Cyprus and Crete, is another possible (although less likely) route to the development of a regional gas hub. The project is currently proposed to transport from the off-shore gas reserves in Cyprus and Israel into Greece and, in conjunction with the Poseidon and IGB pipelines, link into Italy and other South Eastern European countries. While there are significant political risks to the project, the main challenge to constructing EastMed is its cost.

Pipelines and other transportation issues For any project where hydrocarbons are produced in one State and delivered by pipeline to another State, it is important to consider the issues involved in pipelines that cross international boundaries and the cross-border sales of production. These risks can be summarised as follows: • the involvement of two or more governments; • the need to structure ownership and operation of different sections of pipeline in two or more States; • different national legal systems; • different taxation systems; • increased political risk; Any investor should also consider whether there a clear and robust legal regime in place. This would include considering the following: • the terms, and the stability, of petroleum laws and regulations. Law and regulation are sometimes revised by a host State on the discovery of hydrocarbons, although this can involve positive measures such as introducing legislation to encourage investment or specific legislation to allow a project to proceed; • the terms of the relevant production sharing contract, licence or concession; • the terms of any joint operating agreement (JOA) or unitisation and unit operating agreement (UUOA) (if government or NOC are parties); • any relevant treaties, IGAs or HGAs; and

7_16_Bluewater_Layout 1 27.07.16 13.28 Side 1

• the terms of a gas transportation agreement between pipeline owners and producers/shippers The following ultimately will make a pipeline project attractive to potential lenders: • a strong economic rationale; • compliance with Equator Principles (a risk management framework, adopted by financial institutions, for determining, assessing and managing environmental and social risk in project finance); • committed, creditworthy and experienced sponsors; • a robust contractual regime with experienced and credit worthy counterparties; • long-term supply and off-take contracts; • a clear and stable legal and fiscal regime; and • strong government support (particularly with respect to licences and permits).

Tough challenges, smart solutions

Conclusions Developing the various gas discoveries in the Mediterranean is the first challenge, the second is establishing export routes to get that gas to market. At the moment, both are constrained by inter-State tension and the latter also by economics. However, a large new source of gas on Europe’s doorstep presents an attractive opportunity for investors in the region. It remains to be seen which export option or options will be workable, and whether States can work together to establish a regional export hub. For investors in the Eastern Mediterranean, solutions to the risks and challenges can be overcome, or at least mitigated, and should be considered on a project-by-project basis.

Author information

Bluewater has engineered some of the most

Paul C. Deemer (Of Counsel, Vinson & Elkins RLLP)

innovative single point mooring systems in service

Paul’s practice is focused on international mergers and acquisitions, and on the development and financing of international energy projects. He has worked extensively on international oil and gas projects, including cross-border pipelines and LNG projects, in Europe, Asia, the FSU, and the Middle East.

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Anna Chard-Steel (Senior Associate, Vinson & Elkins RLLP)

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today. Our exclusive designs enable the safe and and other fluids, gases and slurries in some of the world’s most challenging offshore provinces. Find out how Bluewater can help you overcome economic, environmental, logistical and technological challenges on www.bluewater.com or send an email

Anna’s practice covers energy projects, general corporate work, and share- and asset-based mergers and acquisitions, particularly in the oil and gas sector, with recent experience spanning Africa, South America and the North Sea.

Steven Wilson (Associate, Vinson & Elkins RLLP)

THE NETHERLANDS

Steven’s practice covers international mergers and acquisitions and energy projects, with a focus on the oil and gas sector.

S C A N D I N A V I A N

NIGERIA

O I L - G A S

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ANGOLA

M A G A Z I N E

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UNITED KINGDOM CHINA

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How low can you go? Exploring for shallow oil in the Barents Sea lntroduction ABSTRACT Recent discoveries in shallow Jurassic rotated fault blocks appear to contradict some of the widely held assumptions regarding seal risk in the Norwegian Barents Sea. As part of regional work, we have evaluated several shallow structures along the northem margin of the Bjørnøya Basin within the Leirdjupet Fault Complex. DEA initiated a research project to understand hydrocarbon fluxes in shallow settings and to link seepage observed on the sea bottom with the shallow subsurface. A combination of 3D seismic and newly acquired high-resolution 2D seismic data have been used to map the shallow overburden and seepage paths of a potential trap. The high-resolution 2D data provided a significant uplift in terms of resolution. On this basis, we conclude that the risk associated with top seal capacity is relatively low, in spite of the shallow depth of the structure. While the faults are prone to re-activation during glacial rebound, the current compressive stress regime is positive for the chances of retention. Dynamic trapping may also release gas from the trap, especially during uplift and erosion, which in tum reduces the buoyancy pressure that otherwise would lead to seal breach.

38 | MED OIL & GAS | October 2018

The Barents Sea is a long lived basin formed by re-activation of inherited structural grains mainly trending in N-S and NE-SW (Faleide et al., 1993 and Blaich et al., 2017 and references therein). In the Jurassic the NE-SW trending grain was re-activated and E-W trending faults were initiated (Blaich et al., 2017; Norkus et al., 2017; Figure 1). Exploration in the Barents Sea has struggled with the “breached seal stigma”: with top seal failure generally identified has the critical risk element prior to drilling and often identified as the cause of failure in dry structures. In spite of this, there have been a series of discoveries with very limited overburden, which seem to contradict this widely held assumption. The 7225/3-1 Norvarg discovery (2011) had only 31 lm of overburden above the gas bearing Jurassic sandstones, whereas the 7324/8-1 Wisting discovery (2013) was even shallower with an overburden thickness of only 237m at the well location and approximately 190m at the crest (Figure 1). It is seen as break through discovery in terms of shallowness and so far the!argest standalone oil find in the Barents Sea with in excess of 1 billion barrels of oil in

place. The setting is comparable to the area of interest for this study and provides many valuable learnings. These recent successes encouraged DEA’s explorationists to evaluate an even shallower target, located in open acreage to the North of DEA operated PL 721 license. Our interest in the area was triggered by evidence of a working petroleum system and the presence of large rotated fault and horst blocks that were identified using multi-client 2D and 3D seismic data. The!argest of these structures is known as the “Svartisen” prospect, which has an overburden of approximately 80m at its shallowest point. Delineation and derisking of the container have proven to be difficult using conventional seismic data due to the hard sea bottom in the area, which results in relatively poor seismic image resolution. However, the results of a recent high-resolution 2D seismic acquisition carried out during the summer of 2017 have provided a new insight into the potential in his area and raised the question “how low can we go?” in relation to overburden thickness in hydrocarbon exploration.

Figure 1 Schematic illustration of the overburden thickness of selected oil and gas discoveries in the Barents Sea (at well locations). The Svartisen prospect in the AOI for this study is approximately l OOm shallower than the 732418-1 Wisting discovery, with estimated overburden thickness of 80m at the apex of the structure, and approximately 110 - 120m in a likely drilling position.

Figure 2 A) Location map; show B) BCU map showing structuring of the working area. Shallow coring sample locations and oil anomalies indicated. C) Seismic quality comparison af different vintages. The new high resolution seismic resolves the upper regional unconformity (URU) hest

Methods and Background DEA Norge and the University of Tromsø initiated the research project “Shallow Seal” (Shallow sea floor environment appraisal of the Northem Leierdjupet fault complex) during the summer of 2017. The aim of the project is to link seafloor studies, including geochemical and microbiological investigations, carried out by DEA Norge during previous years with the evaluation of the shallow subsurface using high-resolution seismic data. The 2017 RJV Helmer Hansen (cruise CAGEl 7-3) acquired 53 2D high resolution lines (highres 2D; Figure 2 C) with a total length of 861 km, together with multibeam bathymetry and water column imaging data for gas seep detection (Petersen et al., 2018, submitted). Several calibration lines were also acquired over the Wisting and Hanssen discoveries further to the east during the same acquisition campaign. Hydrocarbon seeps have been observed by two independent methods: seafloor sampling and water column scanning. However, the seismic datasets do not show clear fluid related amplitude anomalies. The TGS HF13 3D seismic data contains a consistently dimmed window (260ms) below the water bottom, which is related to the processing sequence used to mitigate the impact of the hard seafloor. The seafloor is acoustically very hard and rugged, which also means that most of the high resolution 2D seismic energy is absorbed/scattered early resulting

in limited depth penetration. However, the newly acquired 2D lines do provide a significant irnprovement in terms of the resolution in the shallowest part of the section. The IKU well 7320/3-U-l , which intersected the BCU was tied to both 3D data and high resolution 2D seismic data, which have now been interpreted across the area of interest. Regional 2D seismic data was also been used to provide ties to the 7321/7-1; 8-1 and 9-1 wells in the Fingerdjupet sub-basin.

Results and Interpretation Well observations The shallow IKU 7320/3-U-1 core indicates a working petroleum system adjacent to an oil mature basin, where the prolific Upper Jurassic Hekkingen Formation is expected to be in the peak oil window . Geochemical chromatograms from the IKU well are remarkably similar to those from the 7220/ 8-1 Skrugard discovery, and distinctively different to those from the dry wells in the Fingerdjupet sub-basin (7321/7-1, 8-1 & 9-1; Figure 3A). This allows us to conclude that Skrugard and IKU 7320/3-U-1 have been rejuvenated by fresh, light oil/condensate at a late stage, possibly within the latest Pleistocene to Holocene. In contrast the wells in the Fingerdjupet Sub-basin have not received recent charge or recharge. Seismic observations The Upper Jurassic Fuglen Fm is the main top seal and has been confidently mapped

with the newly acquired high resolution 2D seismic. Although the youngest part of the Fuglen Formation is locally truncated in a few locations above the structure (Figure 3B), a minimum thickness of 40 to 50m is present across the entire Svartisen structure. Regionally, the Fuglen Formation is proven as a good quality seal. The Skrugard oil and gas discovery (7220/8-1) is sealed by 20m of Fuglen Formation at the well location whereas in the Wisting location the Fulgen Fm thickness is 41m. The Fuglen package mapped over Svartisen measures up to 90m in the thicker parts. The Hekkingen Formation is truncated in the crestal part of Svartisen but adds to overall seal thickness down dip. Trapping We have adopted a model for dynamic traps after Sales (1997). In a trap during uplift and progressive filling, gas will ex-solve out of the oil phase and create buoyancy pressure that will eventually break the top seal and re-activate faults. It is likely that those leakage events occurred discretely until pressure equilibrium was reached during glacial (un)loading (“pumping”). In this way the accumulation would behave dynamically and maintain substantial low buoyant oil volume, while exhaling excessive amounts of gas. In its favour, the trap is positioned adjacent to two productive basins and along the spill route from the “Gråspett” structure in PL 721. The lost hydrocarbon volume has been compensated by re-charge . It has a deep 39

Figure 3 A) Observations in the shallow IKU 732013-U-1 core and abundant gas seeps and sea floor sampling show a working petroleum system adjacent to oil mature Hekkingen source; B) Comparison of Hl 3 3D and highres 2D interpretations of the URU above the main horst block and impact on the interpretation of the structure in lower section

structural spill point enhancing the probability for oil retention . Interestingly, the recent stress regime is compressional with maximum stress in the horizontal direction, which should “seal” the major faults (Fejerskov & Lindholm, 2000). Recently Ostanin et al., (2017) modeled the effect of the glacial pumping in the Hammerfest basin and account for 60-80 % of gas loss. This process is likely to benefit taller structures like Svartisen, over lower relief structures in which the oil rim would be expelled more easily. An important analogue for the dynamic trapping concept is seen in the Wisting discovery. With an apex depth of only 600m TVDSS, an oil column at this depth with a high API would normally consist mostly of gas after the uplift . However, the 7324/81 discovery well proved 70m of oil, with an estimated 13m of gas updip. DEA’s in-house investigation indicates that the structure is underfilled with respect to the spill point, which is at approximately 740m TVDSS (57m deeper than the OWC at 683m TVDSS). This indicates that during uplift faults released excessive gas and the accumulation survived with a slightly reduced column as opposed to suffering a complete top seal breach

conformity (URU) and the Fuglen Fm subcrop beneath the URU. Both of these critical elements along with an improved in-house velocity model meant that we doubled the effective top seal thickness at the apex compared to the previous evaluation. This showed that the prospect mapped in the prominet horst may be a valid trap in spite of it’s extremely shallow depth at < 1OOm below the seabed. Seal and retention risk is influenced by multiple factors and is a composite of several elements. We conclude that the top seal capacity is relatively low, as there is a Fuglen Formation layer thick enough, of good quality and with limited evidence of disruption by faulting. The major faults have sufficient throw to allow for clay smear and sand-sand juxtaposition is seen as being unlikely . While faults are seen to be prone to re-activation during glacial rebound, the current compressive stress regime is seen as positive for the retention, as all faults are very steep. The dynamic trapping concept also limits the impact of buoyancy pressure that could lead to seal breach, especially during uplift.

Conclusions The HF13 3D seismic dataset was utilized to map the Svartisen prospect. However, it was not possible to resolve whether or not the Jurassic reservoir section was truncated at the apex of the structure. The new high resolution 2D data allowed a more precise interpretation of the Upper Regional Un40 | MED OIL & GAS | October 2018

Authors

K. Dittmers, A. Dunbar, R. Davies, S. Mackie J. Pettersen & J. Bünz

Acknowledgements We are grateful to the captain, crew and shipboard party of the RIV Helmer Hanssen for their efforts and craftsmanship during the CAGEl 7-3 expedition. Harald Østby is thanked for mapping and maturing the area during 22nd round times. We also wish to thank our colleagues Jostein Herredsvela, Claudio Visentin and Balazs Badics for fruitful discussions during the regional evaluation. References Anell, I., Braathen, A. and Olaussen, S. [2014]. Regional constraints of the Sorkapp Basin: A Carboniferous relic or a Cretaceous depression? Marine and Petroleum Geology 54, 123-138. Blaich, O.A., Tsikalas, F and Faleide, J. I. [2017]. New insights into the tectono-stratigraphic evolution of the southem Stappen High and its transition to Bjørnøya Basin, SW Barents Sea. Marine and Petroleum Geology. 85. 10.1016/j.marpetgeo.2017.04.015 Faleide, J. I., Vagnes, E. and Gudlaugsson, S. T. [1993]. Late Mesozoic-Cenozoic evolution of the south-westem Barents Sea in a regional rift-shear tectonic setting. Marine and Petroleum Geology, 10,186-214. Fejerskov, M. and Lindholm, C.D. [2000]. Crustal stress in and around Norway; an evaluation of stress-generating mechanisms. In Nottvedt. A. (ed.) Dynamics of the Norwegian margin, Geological Society, London, Special Publications, 167, 451-467. Petersen, J., Dittmers, K., Vadakkepuliyambatta, S., Plaza-Faverola, A. and Biinz, S. [2018] Shallow fluid flow in the SW Barents Sea - A multi-scale geophysical analysis. Submitted to 80th EAGE Conference & Exhibition 2018 Sales, J. K., [1997]. Seal Strength vs. Trap Closure - A Fundamental Control on the Distribution of Oil and Gas. IN: Seals, Traps, and the Petroleum System by John K. Sales, p. 57-83; Surdam, R. C. (Ed.): Seals, traps and the petroleum system. AAPG Memoir, 61, pp 57-83. Ostanin, I., Anka, Z. And di Primio, R., [2017]. Role of Faults in Hydrocarbon Leakage in the Hammerfest Basin, SW Barents Sea: Insights from Seismic Data and Numerical Modelling. Geosciences 7, 28. Serck, C., Faleide, J. I., Braathen, A., Kjolhamar, B. and Escalona, A. [2017]. Jurassic to Early Cretaceous basin configuration(s) in the Fingerdjupet Subbasin, SW Barents Sea. Marine and Petroleum Geology. 86. 10.1016/j. marpetgeo .2017.06.044

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Installation of connectors in marine hydraulics Preferably flexible Ships are home to numerous hydraulic systems with extensive pipework networks. A versatile mobile machine is now available for installing cutting ring connectors into the lines. Steering gear and loading systems, flaps and gates, stabilisers and winches: just a few of many applications for hydraulic systems in shipping. There are also diverse other fluid sys-tems, among others for the supply of cooling and heat, ballast water distribution, sprinkler systems and other supply lines.

One vessel – the most diverse tube connector systems In terms of installing the corresponding tubes, that means that numerous different connection elements need to be fitted as well. Tube connectors that comply with ISO 8434-1 or DIN 2353, with metallic sealing or soft-sealing double-edged cutting rings, available from the Stauff Connect range, are commonly used for this. Tube forming systems, such as Stauff Form, can be used to overcome particularly challenging requirements. The range of materials used is equally wide: stainless steel connectors are used outdoors, where salt water resistance is required; steel connectors with suitable surface coatings are used indoors and, in individual cases, special alloys, such as copper-nickel-iron, which offer increased resistance for tubes carrying salt water. Typically, in marine construction there are also a large number of connectors across a large area and a wide range of different tube diameters and wall thicknesses. Some of the tubes are very thin-walled and the clearance between the lines is very small.

Mobile manual installation machine In these conditions, there are really only two serious possibilities for installing or repairing line systems on site: purely manual installa42 | MED OIL & GAS | October 2018

Figure 1: Compact and completely mobile: the new mobile installation machine in the Stauff Press range is ideal for use on site – for instance in shipbuilding.

tion on site with two wrenches or the use of the new installation machine from the Stauff Press range, with product designation SPR-PRC-H-M. The machine can be used practically any where and is ideal for the pressure-controlled installation of all common cutting ring models to the ends of tubes made of steel, stainless steel and other materials up to an outer diameter of 42 mm (Light Series) or 38 mm (Heavy Series). Its use takes pressure off installation personnel, at the same time guaranteeing high-quality reproducible assembly results – even with different tube diameters and materials.

A “lightweight” with stand-alone energy supply The machine boasts two key features that enable it to be used as a mobile unit in shipyards and on ships. The machine is compact in design and – along with accessories and other installation tools – is carried in a trans-

portation case on rollers. It weighs less than 7 kg (including battery), which also simplifies its use on site. The machine can be used as a manual tool or can be installed on a tripod or fitted with a table mounting. An external power supply is not required because, as a “stand-alone” solution, the machine obtains its power from an efficient lithium-ion battery that can typically carry out more than 200 installation procedures without having to be recharged between installations, depending on the diameter of the tubes. A replacement battery is included in the service case as standard. There is also room in the case for the appropriate charging unit. The machine, which Stauff launched at the Hannover Messe 2017, works on the principle of pressure-controlled installation. The setting parameters recommended for the individual diameters of the steel / steel material combinations are practically print-

Figure 2: High-quality tube connectors can be installed reproducibly even in compact conditions.

Figure 3: Everything on board: the machine with accessories and replacement battery comes in a ser-vice case on rollers.

ed directly on the machine and are therefore always to hand. The values can also be adapted for other materials and material combinations, on request, and entered unbelievable easily using the setting wheel on the machine. The installation results are visually checked and evaluated using the clearly visible raised material in front of the first cutting edge of the ring – as is usually the case with cutting ring connectors.

ship-yards and on offshore plants. It is also ideal for the series installation of smaller quantities and for applications in service vehicles and in the workshops of hydraulic repair and maintenance service providers.

Effective corrosion protection even for steel connectors In parallel to this range of machines, Stauff is also extending its industry expertise and product range for marine and offshore technology in its core tube connector segment – on several levels. The company’s Stauff Form system represents a forming system developed from scratch to meet extremely stringent process and leak reliability requirements. From the outset, the entire range of steel connectors, like the majority of the remaining Stauff product range, features a high-grade zinc/nickel coating, which boasts lasting corrosion protection even under adverse conditions.

Excellent flexibility – and high quality As users require only a few seconds to change the tool and alter the installation parameters using the setting wheel, tube connectors of different sizes, series and materials can be effi-ciently installed. “One machine for all applications” – the machine does what it promises. This ensures constantly good process safety and reliability, typical for all machines in the Stauff Press range.

benefit that installation personnel can work more quickly and under less pressure. There is also a significantly lower risk of incorrect or over- or under-tightening, with the resulting risk of leakages, and machine-assisted installation of cutting rings delivers improved process reliability.

Compared to purely manual installation, the use of the installation machine offers the

These properties make the new installation machine ideal for flexible use on ships, in

Author

Jochen Straub Technical Sales Stauff Connect, Walter Stauffenberg GmbH & Co. KG

Photos: Walter Stauffenberg GmbH & Co. KG

A new non-metallic pipe concept:

Thermoplastic Composite Pipes For pipelines to transport oil, gas and their products, steel has been the material of choice from the beginning of the oil and gas industry almost a century ago. Millions of kilometers of steel pipelines have been built since oil and gas started to be extracted in large volumes. During the past decades, pipelines have gone through improvements and optimizations. However, steel of different grades has always been the material used for manufacturing them. Non-metallic material systems like polymers have been used extensively in the oil and gas industry but not for load carrying functions such as the pipeline wall. In industries such as aerospace, maritime and wind energy the use of fiber reinforced polymers or composite materials, which can carry large loads, goes long back to 60s and 70s. However, in the oil and gas industry the adaptations of composites materials have been rare. This tendency to rely heavily on steel to deliver strength for pipelines and use polymer mainly in seals, spacers or at best as a non load-carrying barrier in flexible pipes, has been in part due to the conservative and risk averse nature of the industry. Furthermore, being a rich industry with a limited number of players and monopolies means that you do not need to fight much for competitiveness. If something is working and transporting crude in a safe, affordable and reliable manner from point A to B, the industry will have a limited appetite to change it. Two events changed this mentality in recent years. Firstly, the scarcity of easy oil to extract has pushed the oil companies into much harsher environments, such as ul44 | MED OIL & GAS | October 2018

tra-deep waters. The second is the invention of hydraulic fracturing in the US which led to a massive increase in oil supply and contributed to the crash of oil prices in 2014. As a result, the industry started asking for things which not only work, but also reduce cost and increase efficiency. Competitiveness at low oil prices have become a must to have the oil projects sanctioned. The newly gained focus on cost and performance from the industry has opened the door for innovation. Thermoplastic Composite Pipes (TCP) are one of the most promising innovations using composite materials in the pipeline industry. A TCP is a fully bonded, flexible pipe consisting of a polymeric inner liner ensuring the tightness of the pipe, a fiber-reinforced thermoplastic composite layer ensuring sufficient strength and stiffness and an outer polymer jacket to protect the TCP against external loads such as impact, wear and UV degradation. Thermoplastic composite pipes are manufactured by

additive manufacturing by laying continuous thermoplastic composite tapes. The production is fully automated with the production length limitation of 6-7 km of continuous pipes. To connect the pipes together or to other components, metallic end-fittings similar to flexible pipes are used. Ductility, Spoolability, significantly lower weight to strength ratio compared to conventional metallic pipes and the absence of corrosion, have made TCP a potentially disrupting technology in the pipeline industry. Furthermore, in the new emerging Hybrid Flexible Pipes, TCP is used to replace all the layers of conventional flexible pipes except the tensile armors to save weight and cost challenging the traditional flexible pipes. Various pilot projects across the globe from Asia to Brazil, US, Africa and offshore Norway with different operators have been initiated in the past years to use TCP in offshore oil and gas projects to cut cost and increase efficiency.

To facilitate the adaptation of the TCP technology by the industry, while ensuring the reliability and safety targets comparable to conventional metallic pipes, DNV GL, the technical advisor to the oil and gas industry developed a new standard - DNVGL-ST-F119. Initially in the format of a recommended practice (RP), DNVGL-RP-F119 for design and qualification of TCP was developed in 2015 through a DNV GL-led joint industry project involving 18 companies covering the whole supply chain; from polymer producers, via TCP manufacturers, to oil companies as the end users. The document went through rigorous internal DNV GL and external hearing rounds and more than 700 comments were collected from the industry to ensure the thoroughness and quality of DNVGL-RP-F119. Since its publication, the RP has been the only available document for qualification of TCP in the industry and has been used in almost all the TCP pilot projects across the globe. The design and qualification methodology of DNVGL-RP-F119 has been adopted by all manufacturers of TCP as well as developer of hybrid flexible pipes. After successful and wide adaptation of the RP by the industry for qualification of TCP for various applications from dynamic to static, it was the time for the DNVGL-RP-F119 to turn to an official DNV GL standard DNVGL-ST-F119. The turn reflects the growing confidence in the TCP technology and the methodology of DNVGL-ST-F119 to deliver safe and reliable performance to the industry. The first experiments with TCP are moving fast forward and the early success in installation of them for deep water jumpers and flowlines has been promising. After the first trials with water injection pipes, various operators have been planning to use TCP for more sensitive applications such as carrying oil and gas in deep waters and eventually using TCP for dynamic riser applications e.g. in offshore Brazil. The extent of the adaptation and disruption of the TCP technology is remained to be seen. However, for the first time in its history, polymers and their composites are threatening the dominance of steel in the offshore pipeline industry saving cost and enabling industry in its challenges.

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STAUFF LINE Author

Ramin Moslemian Principal Specialist â&#x20AC;&#x201C; DNV GL Ramin Moslemian is a composite materials and polymers principal specialist at DNV GL. He has a PhD from the Technical University of Denmark (DTU). The main areas of interest include mechanics of thermoset and thermoplastic composites, manufacturing technologies, environmental aging, long term integrity of composites and probabilistic approach to engineering problems.

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46 | MED OIL & GAS | October 2018

NEWS RELEASE

Rotech Subsea clinches two major scopes of work in Middle East Rotech Subsea Ltd. has announced that is has secured two major scopes of work in the Persian Gulf, Saudi Arabia worth over $1m. The first offshore Saudi contract for the Aberdeen-based subsea excavation contractor - a significant cable post-trenching scope - saw its TRS1-LD tool mobilised within days and collected from Rotech’s fabrication yard by the client. Rotech Subsea has also clinched a 42 inch pipeline post-trenching and remedial gig in Saudi Arabia with its TRS2 tool shipped alongside the TRS1-LD. This follow-on contract is the latest in a series of major scopes awarded to Rotech in the region. The TRS2 tool, which was mobilised out of Aberdeen, was selected despite alternative equipment being available in-country, a real vote of confidence in Rotech’s equipment and people. Regional demand is such that these tools will remain in the Middle East as Rotech establishes a permanent base in the region.

Rotech setting up Middle East hub to meet demand In response to unprecedented demand for Rotech’s state of the art subsea excavation tools in the region - and a series of major contract awards for key clients - the company has accelerated plans to set up a permanent base in the Middle East that will see its TRS1, TRS1-LD, and TRS2 tools kept in-region. The company will also seek to make a number of key appointments to support the expansion. “Demand for our range of cutting edge Controlled Flow Excavation (CFE) tools in the Middle East was strong last financial year and shows no sign of abating,” said Rotech’s Director of Subsea, Stephen Cochrane. “We’ve been inundated with enquiries for our tools, including our TRS1-LD system for shallow water projects - which is the most powerful tool on the market - and

anticipate busy times ahead in the region. To meet the demand we have accelerated our plans to set up a permanent base there.” It has been a stellar rise for Rotech Subsea since the subsea excavation pioneer - with a three-decade track record in oil, gas & renewables - announced their return following the sale of technology that took the sector by storm in the 1990s. Rotech emerged from the ensuing non-compete period in 2015 with a bang with their new and more precise Controlled Flow Excavation (CFE) range and within weeks its cutting-edge RS1, TRS1 and Backfilling systems were deployed on commercial projects. 2016 saw Rotech Subsea launch the next generation TRS2 systems for major sandwave clearance and pipeline trenching scopes. The groundbreaking CFE technology that has caused such a stir provides a more targeted jet, leaving a deeper, narrower and more uniform V-shaped trench than was previously possible. It reduces the risk of damage to cables compared to tracked vehicles as well as being cheaper and safer to deploy. It is also twice as fast and up to four times more powerful than existing technology. These capabilities have seen Rotech’s TRS1 adopted as a true cable-trenching tool, suitable for commissioning works, not just IRM. Projects so far have seen trenches created

to 6 m deep in a single pass, and progress rates up to 6 m per minute. The past year has seen Rotech deploy their game-changing CFE technology throughout European, Asian and Middle Eastern waters. Enquiries are coming in daily for Rotech’s TRS1 Low Draft (LD) - which is most powerful shallow water tool on the market - being able to operate in water of 1m depth - and the next big thing in subsea excavation. Rotech Subsea Ltd. recently marked a major milestone by completing its 500th subsea project - all safe and successful. The milestone, which the company has racked up since beginning operations under the Rotech Group banner in 1994, was passed after Rotech Subsea mobilised for four major projects in the month of May 2018 alone - worth over £1m - with two vessels sailing from Aberdeen in the space of just nine days. For more information please contact:

Stephen Cochrane Director of Subsea Rotech Subsea Limited | Rotech House | Whitemyres Avenue | Aberdeen AB16 6HQ Main: +44 (0)1224 698698 subseainfo@rotechsubsea.co.uk www.rotech.co.uk

Olympia, London 27-29 November 2018 75+ Exhibitors 180+ Speakers Expected attendance of 3000+ 40+ Countries Represented Numerous Networking Opportunities The UK’s largest subsurface-focussed global E&P conference and exhibition

Exciting Keynotes William Zimmern Head of Macro Economics BP Tony Doré (co-authored by: Harald Brændshøi) Senior Advisor to Exploration Management (Vice President for Exploration Portfolio & Strategy) Equinor Ed Harbour Vice President, Watson & Cloud Platform Client Success IBM Maurice Nessim President WesternGeco 48 | MED OIL & GAS | October 2018

www.petex.info

NEWS RELEASE

Wintershall calls for unified action by Europe to ensure its supply security • Norway plays key role in future energy supply • CEO Mario Mehren: “Europe must act in concert!” • Growth in Norway: Wintershall DEA would be among the top five gas and oil producers Stavanger Europe is well advised to invest in collaborating with reliable and proven supply countries to secure the future energy supply. This is what Mario Mehren, CEO of Wintershall, underlined today at Norway’s largest energy conference and exhibition, Offshore Northern Seas (ONS) in Stavanger. “Europe needs to be aware of its strengths and must tackle the new political and economic challenges in concert. Only through closely collaborating with our neighbors can we guarantee supply security today and in the future,” Mehren explained at the Wintershall press conference at the ONS. Norway and Russia in particular, as the EU’s long-standing reliable energy partners, have a key role to play. “Both countries are and will remain the decisive energy partners of the European Union,” Mehren added.

Considerable development potential in Norway Wintershall is therefore banking on growth in Norway and plans to invest a total of around €2 billion in exploring and developing its fields on the Norwegian Continental Shelf from 2017 to 2020. More than a third of Wintershall’s global exploration budget will

be used in Norway. “Our project pipeline is well filled! Wintershall already holds over 50 licenses in Norway today. We believe in the potential of the Norwegian Shelf. Here we also see one of our core production areas in the long term,” explained Martin Bachmann, the Wintershall Executive Board member responsible for exploration and production in Europe and the Middle East, at the press conference. This strategy distinguishes Wintershall from many major competitors in Norway: “Wintershall has consistently invested further in Norway,” said Bachmann. “And what’s more, we want to grow in Norway. For 2019 alone, we’re planning four new exploration wells. The execution phase for the Nova project already started in early summer and plans for a possible development of our Balderbrå prospect are also progressing. We expect a further increase in our production volume with the start of Aasta Hansteen before the end of the year.”

Nova: Wintershall continues to expand its subsea expertise “When developing our projects, we rely on innovative technical solutions and smart project management,” explained Hugo Dijkgraaf, Managing Director of Wintershall Norge. “This enables us to remain profitable even with volatile prices.” Wintershall plans to develop the Nova field, whose Plan for Development and Operation was submitted in May this year, using two subsea templates. These underwater production systems will be connected by pipelines to the existing infrastructure belonging to the neighboring Gjøa platform. “Using existing infrastructure instead of building new installations not only 49

saves time and costs but also protects the environment. This approach is technologically, environmentally and economically exemplary,” said Dijkgraaf. Wintershall and its partners expect to invest a total volume of around €1.1 billion in the development of Nova. The recoverable reserves from the field are estimated to be around 80 million barrels of oil equivalent.

Wintershall DEA: One of the largest producers in Norway Once the proposed merger of Wintershall and DEA, a subsidiary of LetterOne is completed, the new Wintershall DEA company would be among the top five oil and gas producers in Norway. “Wintershall and DEA have been firmly established on the Norwegian Shelf for years. Norway would become an even more important growth region for Wintershall DEA and – after Russia – by far the largest production location. With more than 100 licenses and shares in 20 producing fields, we could increase our joint production in Norway to over 200,000 barrels

of oil equivalent per day in the near future,” said Mario Mehren at the press conference in Stavanger: “Within a decade we have grown from a small project office into one of the most important E&P players in Norway.” Norway’s energy policy makers have also contributed to this success story. The gas and oil industry is the main cornerstone of the Norwegian welfare system. More than 200,000 people work in the industry, accounting for over 40% of exports. “I’m convinced that the Norwegian Continental Shelf has a future – but that shouldn’t be taken for granted. Investments must continue,” Mehren said.

“Europe has to play its trump cards” The stable and reliable energy partnerships with Norway and Russia will become even more important for Europe in the future. “Take for example gas. Demand in the EU is rising, but domestic production is declining – which in short means that the import

demand is increasing. In 2030, for example, the EU will have to import around 400 billion cubic meters of natural gas,” Mehren explained. “In order to meet this increasing import demand, we need reliable partners, especially in pipeline distance. Nord Stream 2, for example, will provide an additional capacity of 55 billion cubic meters of natural gas when it is completed. This is natural gas that Europe needs,” the Wintershall CEO underlined. Natural gas is also making a significant contribution to Germany’s and Europe’s energy transition and to reducing CO2 emissions. Without natural gas as the most climate-friendly fossil fuel, the EU could not achieve its climate goals. “Europe has the advantage of being able to use its geographical proximity and direct connection to the large energy reserves in Norway and Russia in pipeline distance,” Mehren said. “Our well-established and reliable partnerships in particular with these two countries are essential for achieving the climate targets. Europe has to play its trump cards.”

Pipe Manufacturing • Transport brushes in hot zones • Cutback brushes for coating removal

Exploration, Drilling & Construction • Tools for weld preparation, grinding and cleaning • Well bore brushes • Oilskimming brushes • Drill pipe cleaning brushes

Pipeline Inspection & Cleaning • Custom engineered pencil brushes and assemblies • Coil brushes • Arc-style brushes • Straight wire strip brushes • Tri-Flex/Flex-Pig brushes

Simply the best for Pipelines

50 | MED OIL & GAS | October 2018

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52 | MED OIL & GAS | October 2018

NEWS RELEASE

KOSO Kent Introl:

Full Service Subsea Valve Provider Since 1985, KOSO Kent Introl has supplied over 900 subsea valves to the industry from its UK facility in Brighouse, West Yorkshire. As well as control and surface choke valves for standard and severe applications, their dedicated engineering team engineer custom design solutions for subsea projects around the world.

“We’ve built on our knowledge and experience of subsea applications in recent years with some very significant projects and this is another milestone in our development for subsea products. We now have a high pressure API 6A/API 17D qualified subsea choke valve and we’ve risen to the challenge of developing it to meet the needs of some very demanding conditions. This gives us a great opportunity to provide solutions to other customers with similar HPHT applications along with the confidence of a fully qualified product.”

Custom design subsea valve engineering KOSO Kent Introl engineer and supply custom design, high-quality valves to perform in some of the most severe service conditions throughout the world. As experienced valve manufacturers they have built a reputation for providing high-performance products to schedule and at a competitive price. The team at KOSO Kent Introl recently completed the production of their highest pressure subsea valve to date, capable of 15,000PSI the high-pressure valve is fully

Subsea valve overhaul and upgrades qualified in accordance to the latest editions of API 6A/API 17D. Utilising KOSO Kent Introl’s eight-stage, solid tungsten carbide multi-spline trim, the valve is capable of handling the extremely high-pressure drops and associated velocities safely, avoiding potential damage to the valve and downstream equipment. The valve trim also includes an internal cleaning function to clear any upstream particles, preventing both blockages and any potential downtime. KOSO Kent Introl’s Sales Director, Stuart Billingham says:

KOSO Kent Introl’s expertise in subsea valve overhaul and upgrades can help ensure that your valves and equipment run safely and cost-effectively. Financial pressures in the market have made it essential to maximise the service life of your equipment. KOSO Kent Introl’s dedicated aftermarket and testing facilities provide them with the scope to manage entire overhaul and upgrade projects in-house, from start to finish. A recent project saw the team at KOSO Kent Introl conducting an overhaul of six existing subsea choke valves that had been operat53

ing in an oil and gas field within the North Sea. The reservoir in question had a low gas to oil ratio and required pressure maintenance through water injection from the onset of production. Initially the valves operated successfully for a number of years without issue. However, in 2010 additional water was introduced to the process which mixed with the treated seawater. As a result the water injection flow rates were increased significantly resulting in damage to the subsea choke valves.

54 | MED OIL & GAS | October 2018

KOSO Kent Introl reviewed the existing design with a view to upgrading the valves for a long-term solution. Their engineering and aftermarket teams proposed several design enhancements and material upgrades to the main trim components. The updates and enhancements have ensured that the effects of both vibration and erosion will not occur to the valve in the future.

Full service subsea valve provider KOSO Kent Introl can provide a full service from the supply of custom design products

at the execution stage of new projects to the refurbishment and upgrade of in service products. Based upon ever changing field conditions, their services can maximise service life while still achieving high production in some of the most severe service conditions throughout the world.

KOSO Kent Introl Tel: +44 1484 710 311 Email: info@kentintrol.com www.kentintrol.com

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Butterbrot Kindergarten Heimat Oktoberfest Wunderkind Energiewende

Zuverlässigkeit From Butterbrot to Energiewende, many German words are known round the world. We’ve added one more to the list: Zuverlässigkeit, meaning reliability. That’s what we, Germany’s biggest oil and gas producer, stand for in Europe, North Africa, South America, Russia and the Middle East. www.wintershall.com