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Offshore Europe in Aberdeen report: - CEOs of BP and Shell share their views on future of North Sea, cybersecurity, biggest threats and carbon - New business models for the industry - Latest thinking on how to make digitech work Professionalising oil and gas data management

November - December 2017

Intrisincally safe tablets offshore changing how people work?

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Events 2017 Solving E&P problems with Machine Learning & Analytics London, 20 Nov 2017 Transforming Offshore Operations with Digital Technology Stavanger, 29 Nov 2017 The Eastern Mediterranean... the gas “sweet spot” in the East! London, 13 Dec 2017 Fractured Reservoirs and other rocks! ...in the Middle East, West of the Shetlands, the USA London, 23 Jan 2018 Mature provinces... the North Sea and beyond! London, 21 Feb 2018 Gas to power - and the oil and gas industry... What happens when the oil and gas industry gets involved in gas power generation? London, 21 Mar 2018 New Geophysical Approaches London, 24 Apr 2018

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When approaching digitalisation - separate platforms and tools Issue 68

November - December 2017

Digital Energy Journal United House, North Road, London, N7 9DP, UK www.d-e-j.com Tel +44 (0)208 150 5292

Many companies are trying to answer the question of how to approach digitalisation. Many senior managers have grasped the idea that there is value in analytics but not much idea how to go any further. Here’s my idea - separate platforms from tools.

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The tools are what people in the industry - geoscientists, engineers and others - use to do their jobs. Developing tools can be a great business for a start-up. Perhaps staffed with one domain expert, a former oil and gas subsea engineer say, and someone who knows their way around an IT system. It is a business with high risks and high rewards - difficult to get a tool right, but if you get it right you can sell it by the thousand. Getting tools right needs iteration, care and close working relationships with the customer. This is something small companies can often do better than big companies, since big companies tend to have more meetings, long term planning, risk minimisation, multiple layers between the software developer and the customer, and when they have to, hackathons, which sound like “spend all night trying to make something which works but end up with no idea about how it works”. It is pretty hard to iterate something nobody understands.

Cover image: Aegex Technologies of Atlanta has developed an intrinsically safe (explosion proof) tablet computer for $2295. Could it lead to changes in how companies work offshore? See page 20

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It is great if the domain expert who is actually doing the work, such as an actual subsea engineer, can build tools themselves, because they know exactly what they need and have the highest motivation and reward from getting it right. Just like in the non-digital world, many people like to build their own tools. And a tool isn’t necessarily a piece of software - we are starting to see companies making 3D prints, in plastic, of

subsea infrastructure, so staff can better understand it. Developing platforms, however, is very expensive and hard - something perhaps only for oil majors, governments, large software companies. Perhaps not even mid-sized oil companies have the resources to put together a rigourous data management platform, for example, but the oil majors usually do. A “platform” is not a specific term think of it like a theatre stage or a school playground, something which someone makes for somebody else to do something in or with. Making platforms robust can be very dull work, certainly not very glamourous, and a long way from where senior manager’s attention usually is, and a long way from making money. That’s why it’s hard. In digitalisation, a platform can mean data standards, data management governance, data storage, data availability, cloud hosting. It can mean a software system where (for example) the company manages all of its well logs or subsurface data. It can also mean the ‘app stores’ developed by Paradigm, Schlumberger, Intelligent Plant. It can mean ABB’s “Ability’ Platform. It can mean a database system (Eigen) or a data integration system. It can be a line of data gathering systems (sensors), or a system of intrinsically safe hardware. Perhaps a general approach to start off with might be to say, whether you should develop a tool or improve (or develop) a platform depends on who you are. If you are from a government agency or oil major, look at the platforms, and if you are from a start-up look at the tools? There are exceptions to all of this, as the articles in this issue show, but also just about everything could be described as either a platform or a tool. So this may be a helpful way to understand how to do it.

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Leaders

Bob Dudley at Offshore Europe Bob Dudley, CEO of BP, gave an interesting talk and q+a at the plenary session of Offshore Europe, covering BP’s focus on the North Sea, working with suppliers in new ways, cybersecurity and carbon “We’re seeing a lot of new focus in the [North Sea] basin and I’m really pleased about that,” said Bob Dudley, CEO of BP, speaking at the plenary session of the Offshore Europe conference in Aberdeen in September.

and who would do what,” he said. As an example, BP was affected by “this Ukraine virus”. The company had staff who “immediately cut off 4 countries, without waiting for some authorities [to say it was OK],” he said. This is something they had previously practised doing in a drill.

At BP, “we’ve focused on key areas in the Central North Sea and the West of Shetland. BP is a partner in 6 exploration wells in the UK, more than we’ve drilled in decades,” he said. BP predicts that the world’s energy demand will keep on growing, up 30 per cent in the next 2 decades. “We have [already] re-invented ourselves in part and need to continually re-invent ourselves.” The industry needs to look at how it runs its existing businesses (improving efficiency and competency), possible new business models, and ways to build partnerships with governments and suppliers. In terms of the existing businesses, “we need to find ways to do more with less,” he said. “Leveraging automation, digitisation and new ways of working”. As an example, BP is currently trialling seismic capability using ocean bottom cables on the Clair Ridge, together with acoustic sensors inside wells. “We think this will completely transform the detail and clarity of reservoir imaging, as well as enabling much closer well monitoring. We recently trialled a new method of positioning drilling rigs – all done remotely with the surveyors staying onshore, so it could prove to be a safer operation as well as lower cost,” he said. Standardising processes can be transformation “in some areas,” he said.

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OPEC and oil price Bob Dudley, CEO of BP

a company set up by merging BP Norway with Det Norske, a Norwegian oil company (where the Aker group has a large holding). This merger combined the strength of BP Norway, which is seen as its “technical expertise and long experience with the basin”, with the strength of Det Norske, which Mr Dudley sees as its “streamlined operating model”, forming long term relationships with suppliers (note – this is explained in more detail in article on page 16). “It’s a new model but one that is working really well in this case,” he said. We shouldn’t expect computers to do everything. Mr Dudley emphasised that “the human touch is and will be needed in the future”. “This region [Aberdeen] has been a leader in re-invention,” he said. “It has been a tough time, but in this tough environment we see the North Sea turning things around.”

Cybersecurity In the q+a, Mr Dudley said that the subject of cybersecurity has become “quite extraordinary. People talked about incredible damage that was done to companies.” Just a few years ago, the main concern was about accidents.

Also business models are changing, particularly with the fuel mix, with gas becoming increasingly important due to its lower carbon. Oil and gas companies are trying to find ways to get closer to their customers.

As a result of cybersecurity concerns, the trend has changed more towards disintermediated systems (which are not connected electronically) rather than ever more integration.

BP is using “venturing”, investing in new technologies like venture capitalists do, as a way to “screen” new technologies for what they offer.

And it is important to be able to disintermediate a system immediately – such as disconnecting a plant from any link to the internet – if there are signs someone is managing to hack in.

The company is also looking at working with suppliers in new ways. One example is Aker BP,

“I think it is important for everybody in this room to go through a drill, what would you do

digital energy journal - November - December 2017

When asked about whether OPEC was still relevant, Mr Dudley replied, “I don’t think it is becoming irrelevant, generally it does have discipline. As an example, the OPEC countries were able to meet up with non OPEC countries and set oil price targets. “The oil price has stabilised and it is partly due to that agreement.” “Maybe a price in the $50 range is a healthy thing,” he said. “It is not $25 that creates stability.” We will know more about what OPEC will do at the next meeting next March, he said.

Suppliers When asked whether risk and reward were being properly shared in the supply chain, Mr Dudley said that last time oil prices crashed, operators sent out letters to all their suppliers demanding 15 per cent price reductions. This time “it is much better”, with all companies in the chain adjusting their entire cost structures. If you have a situation where whoever has the most market power dictates terms to the weaker companies, “It doesn’t lead to good relationships down the road,” he sad.

Race to be second When asked what can be done about the famous oil industry “race to be second”, where no-one wants to be the first to try anything, Mr Dudley noted that “we are already second as an industry,” said BP’s Mr Dudley. “[Consider] the lack of sensors all through our facilities. It is nothing like other industries [such as] aviation and automotive.”

Leaders

Shell’s Ben van Beurden at Offshore Europe Ben van Beurden, CEO of Shell, talked about his company’s commitment to the North Sea, maintaining workplace attractiveness, and non US shale

Ben van Beurden, CEO of Shell

Ben van Beurden, CEO of Shell, emphasised that Shell is still committed to the UK – despite divesting $3.8bn of assets in the North Sea, decommissioning the topside of its Brent Delta platform, and cutting costs in response to the oil price.

Mr van Beurden emphasized that renewable energy is currently only used to make electricity, which is about 20 per cent of the world’s energy system, and overall, energy demand is going to go up.

applications for “new energy jobs” compared to traditional jobs.

“If costs are low and investment landscape is stable, the world will be relying on work done here in the North Sea for years to come,” he said.

Non US shale

Workplace attractiveness

The company has deep roots in the UK, which means “deep commitment”.

In the Q+A, Mr van Beurden said that companies with a good reputation usually have no problem attracting people. The hardest part can be keeping the interest of people who have committed to be part of the industry.

“The company intends to invest hundreds of millions of dollars a year in this area over coming years,” he said, such as with redevelopment of the Schiehallion area.

“People want to work in an industry that matters,” he said. “The things you get to do in our industry are phenomenal, technically and relationship wise.”

However, the focus on cost will have to continue. “The work is not done - the basin still has to earn its right to grow. It must be competitive for investment,” he said.

But there are people who “don’t want to be accused of [working for] a dinosaur industry at birthday parties and barbeques.” As an illustration, the company gets about 25 times more

“We have to keep reminding people of the relevance of our industry,” he said.

When asked where he thinks the most interesting places in the world are for shale apart from the US, Mr van Beurden cited shale from Argentina “in lower quantities”, Bazhenov in Russia, and North Africa. “We put a lot of effort in China - it didn’t quite work out,” he said. The US is the “main hub” for unconventionals, with its established supply chain, wealth of data and legislative structure. Other parts of the world “don’t have the advantages that North America has,” he said. “It is a factor of governmental willpower and ability of companies when basins get developed,” he said.

Peak oil, climate change, threats and standardisation In a panel discussion at Offshore Europe, Bob Dudley, CEO of BP, Ben van Beurden, CEO of Shell, and Robin Watson, CEO of Wood Group, shared perspectives on peak oil, reducing GHG emissions and the biggest threats “We’re never going to see peak supply of oil,” Mr Dudley said. “We find more and more with [new] technology.

But even if demand drops, “it is not the end of our companies,” he said. “We have tremendous adaptability.”

“Ultimately, if you look at climate change, [solving] it is all possible and viable, and it is not going to tank the world economy.

“[But] we will peak in terms of demand for oil. There will be a point in time.”

Shell’s annual investment is equivalent to about a tenth of its total assets, so you can say that the company completely rebuilds itself every 10 years, he said. “So every 10 years a new Shell. We will adapt before peak oil.”

“Without CCS there is no hope to meet the Paris commitments. It is not going to happen automatically.”

“It will be some time out there. But it won’t be a peak and it drops off, it will be a long curve down.” “Media estimates vary from tomorrow to the second half of the century. The real answer will be somewhere in between.” Shell’s Ben van Beurden said that the subject “has an element of obsession around it. And an element of media want our industry to be obsolete.”

GHG emissions When asked for the best way to reduce greenhouse gas emissions, Shell’s Ben van Beurden said, “We have been pushing for a carbon price for decades.” Mr van Beurden said that he regretted that “we haven’t been harder hitting on the price of carbon,” he said.

“But it doesn’t make commercial sense to do [CCS]”, he said. “We need parameters that compel and motivate us to invest in these things. Don’t expect us to inflict self-harm. Do expect us to put our money where our mouth is when conditions are there.” “We were involved in a CCS project in Scotland pulled at the 11th hour due to different priorities in the Treasury.” The cost of CCS “has to go through the same cost curve as renewables.”

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Leaders Ingenuity and technology When asked what the most relevant new technologies are, Wood Group’s CEO Robin Watson said that ingenuity can be more useful than just technology – working out how to use technology usefully. Also “taking the digital environment into the field” – giving field workers the same sort of digital tools that office workers has, has proven to be “Fairly simply technology but useful technology”. From left to right - Robin Watson, CEO of Wood Group; Solange Guedes, Chief Exploration & Production Officer, Petrobras; Catherine Macgregor, drilling group president with Schlumberger; Ben van Beurden, CEO of Shell; Bob Dudley, CEO of BP; and Janeen Judah, president of SPE

It may have been a mistake for oil companies to promote CCS as a solution for power generation (rather than for industry) – because in gas and power, it relies on Shell’s customers (who buy gas to burn in power stations) to do it.

and environmental incidents.”

CO2 emissions from industries of all kinds are as large as CO2 emissions from power generations, and this includes plants which oil companies run, such as petrochemical plants.

He also thinks about how Shell can “establish beyond any shadow of a doubt our company is a force for good in society.” The company needs to retain its “societal license to operate.”

But for now, governments think that reducing CO2 is “all about renewables,” he said.

“If may not be a big deal in Aberdeen or Brazil, it is not an issue in sub-Saharan Africa or India, but it is an issue in our home countries,” he said.

“At some point people will wake up. CCS will come back and we have to be ready for it.” BP’s Mr Dudley said that if the industry is going to be able to promote gas as a “natural transition fuel” (between coal and renewables), it needs to get away from criticism about methane leaks. “It is the Achilles Heel of a natural low carbon fuel.” BP is part of an industry wide scheme to find out what the methane leaks actually are, and to eliminate flaring.

Threats When asked what they saw as the biggest threats to the company, BP’s Bob Dudley noted that BP “has been a case study in terms of what you worry about in terms of survival”. The Deepwater Horizon disaster “has changed the culture of the company. We have learned so much”. One particular worry was class action legal suits in the US. “There’s something wrong with that [system],” he said. “This was a huge threat to the company. I’m not worried about the survival of BP now, but I really was. I’m not as worried as I had been.” Shell’s Mr van Beurden said that his biggest worries are “what can go wrong in terms of safety 6

And he also thinks about how Shell can demonstrate it is a world class investment case. I’m reasonably confident [that] we will get there.”

The company needs “much more focus on society dimensions. We can’t just be good solid engineers,” he said. If this is not addressed, eventually, “it will come to bite us.”

Standardisation When asked if he could “commit on record to do a step change in standardisation,” Shell’s Mr van Beurden said that “standardisation is very important, we have been on a standardisation journey for some time.” “Often it has been internal standardisation, [but] the real benefit comes if we do it across the industry. It is also tough to get it right.” As an example, there has been an industry wide project on standardising Christmas trees, but Shell thought the standardisation could have gone further. It is important to make sure the commitment in the company runs high, and the standards are being used. Wood Group’s Robin Watson said that standardisation can be helpful if it leads to simplified equipment and processes. But it can also be a distraction if it leads to too much focus on “how we do things” rather than what is actually achieved.

digital energy journal - November - December 2017

Janeen Judah The theme of the conference was “embracing new realities, reinventing our industry.” New realities are the low oil price, the increased number of younger professionals in the industry (described 10 years ago as the ‘big crew change’), and also renewable energy, decommissioning and changing political realities, said Janeen Judah, president of SPE, in her introduction to the conference. “Re-inventing the industry”, means introducing new technologies and being more efficient and effective in how oilfields are operated, she said.

Catherine Macgregor Catherine Macgregor, drilling group president with Schlumberger, and chair of the Offshore Europe committee, said that the industry can become more sustainable through more collaboration, better use of technology, and “fully embracing digital transformation”. “We are still seeing many projects plagued by inefficiency, overlaps in responsibility, silo mentality - optimisation of parts don’t necessarily mean optimisation of the whole system. Trust needs to be re-established.” The industry has “always been very good,” with technology, she said. Perhaps the best way to reduce cost is through “tech savviness”. For digital transformation, the industry can use digital technology to help “optimise pretty much every aspect of what we do”. For example, it is possible to reduce turnaround time for seismic projects from 18 months to 2 months, and do much more with the available production data, optimising how facilities run from a production and reservoir point of view. The oil and gas industry can learn from other industries which had to re-invent themselves over past decades, including automotive, aeronautic and mining, she said.

Subsurface

Target - a cloud data repository for Oman Target Oilfield Services is building a cloud based data repository for the Oman government – and finding that putting data on the cloud can make it easier to manage. Would oil companies get the same benefits from cloud based data hosting? Tier 3 (99.98 per cent availability) data centre in Oman.

Target Oilfield Services, a company based in Oman but with digital services provided from the UK, has been building a cloud based data repository for the Oman government, to manage its oil and gas data. Oman awarded Target the contract to manage its national data repository (government owned oil and gas data), after the previous operator had run it for 5 years. Oman wanted to get the oil companies supplying data to carry out these tasks, taking responsibility for quality control of the data they own. They also wanted data to be cloud hosted, so that oil companies would be able to load data themselves. Before Target became involved, there were many staff members employed to manage the data repository, including doing data clean-up and loading, covering seismic, wells and GIS data. The Oman government also wanted a data store to be based on open standards, so it would be easier to move the data to a different service provider in future, should it want to. The Oman government also liked the idea of paying for the service on an ongoing basis, rather than making a capital investment. They wanted the data, including 10 petabytes of seismic, to be hosted within their own country. The Oman government wanted to make it possible to interact with the data as visually as possible, not just have people looking at data. This includes being able to visualise seismic without downloading it. The government also wanted a system it can use to manage its ongoing bid rounds, providing data to companies considering bidding for license blocks. (You can see this online at ldr. omanbidround.com). So altogether this means a transformation of the commercial aspects, user experience and operating model, says Jamie Cruise, president of digital services at Target. Target chose to put the data into the PPDM standard data model format, hosting it in a public

Migrating the data to Target’s software system took 12 months. Today, data can be accessed just from entering a URL into a web browser, no software is required. Jamie Cruise, president of digital services, Target

To make the data easier to visualise, nearly all of the data is accessed via a map or other graphic. “We have a passion for making sure we don’t present bland tables of data to people,” he said. “Our users require more than that.” Once the cloud data server was set up, Oman found many more document types it wanted to store on it, including data connected to bid rounds, work programs, budgets, regulatory information, collaboration work with operators, and feedback on regulations. In building the system, it was important for Target to see itself as a supporter of critical organisational decision making, not just running a database, Mr Cruise said. For example, it needs to understand what information a regulator needs to ensure that companies are in compliance with oil and gas regulations. This means being focussed on workflows and data integration, not just focussing on data repositories, he said. Target developed its software using Amazon Web Services, but because most production data needs to be stored within the country where the production happens, the software needs to be transferred to a local cloud data provider before being operational. Jamie Cruise has been writing web based information management software since the 1990s, for a company which was sold to Halliburton. He went on to found a company called FUSE Information Management in 2005, which was acquired in 2014 by Target Oilfield Services, a company based in Oman.

Offering software to the public Next year, Target plans to take its system to the market as a “public cloud offering”, an online software service, like Microsoft’s Office 365. Companies will be able to buy their own “instance” of the software online. The company sees a potential market from oil companies which don’t already have an infrastructure to manage their corporate data. As part of the system, it is possible to build 3D “scenes” of subsurface data, using technology developed to draw 3D city maps. The view is good enough for data quality control, but not for doing interpretation directly on it. It is possible to work with seismic post stack data in this way, doing some basic quality control. Using the system, oil companies will be able to search for and access information via map interfaces. This can either be done via ESRI GIS software (if you have an ESRI license), or through an open source GIS system (which is free). The system can provide mapping data from any company, if it supports WMS (Web Map Services) and WFS (Web Feature Services) standard. It is very important to make the system easy to integrate with other systems. Mr Cruise sees Twitter as a company which has created a particularly easy to use Application User Interface (API). The APIs for some oilfield software are very complex. Target is considering using GraphQL, a data query language designed to keep multiple data stores updated without needing too much data transfer. It was developed internally by Facebook for keeping Facebook pages updated from multiple data sources in any structure. The language was released by Facebook for public use in 2015.

Easier when centrally managed The work showed that data management can be easier when data is stored on the cloud, with all of the data in one place and centrally managed, said Mr Cruise.

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Subsurface This is not the first time data has been centrally managed – it was also centrally managed in the pre-digital era, in libraries, and it was centrally managed when it was stored on mainframe computers. Both systems had strict rules about how the data should be managed, to maintain quality and ensure accessibility. Decades from now, the era of storing files on individual PCs, and having multiple versions of files circulating around the company, might look like the anomaly, Mr Cruise said. Workstations made life easier for workers, but meant a big increase in the challenge for data management governance, he said. Now, as oil and gas data increasingly moves to cloud servers, “we’re hopefully entering a new era of data management with more well managed, centralised environment,” he said. “We can go back to having one version of each piece of data. That will make our business processes much more effective.”

Future role of data managers One question is what the role of the data manager will be from now on. Some people assume that data managers will no longer be needed, as “middle man” removed by technology – files can be loaded and downloaded by the people who create them or need them. Some people think data managers will need to become data scientists, developing skills for statistical analysis of data. Mr Cruise’s personal view is that there will always be a big role of looking after data and ensuring data quality and standards (governance). “Our responsibility as data managers is ensuring the right data is delivered to the right person,” he said. The oil and gas industry keeps all of its data from the past – “we carry our legacy with us,” he said. None of the old data can be ignored.

Matthias Hartung, President Digital Transformation - Target Oilfield Services and a former VP technical data with Shell, noted that a common fault of data managers is to try to get everything perfect, in the belief that perfect data is what the business mostly needs. The professional trait most missing is curiosity, he said. A curious data manager will work out what internal customers need – and whether they are being provided with it, and if it is possible to provide it.The data manager understands why this adds significant value, and understands the most important data requirement for the most important business, process or customer being served. Another essential ability for data managers is communication skills, explaining how data assets can be leveraged to enable well-informed business decisions, using language the customer understands. Data and digital can transform the upstream from being laggards to leaders in energy solutions, they are mutually supportive and need each other to succeed, Mr Hartung said.

PPDM – professionalising data management The Professional Petroleum Data Management Association (PPDM) is developing ways to improve the professionalism of data management – and continuing to develop its standards The Professional Petroleum Data Management Association (PPDM) wants to see oil and gas data managers recognised within the industry as professionals, said Trudy Curtis, CEO of the Professional Petroleum Data Management Association (PPDM), speaking at a PPDM lunch in London in September.

PPDM also organises events, publishes a magazine, and organises professional development programs. It has lunches, workshops and conferences planned in Calgary, Dallas, Oklahoma, Denver, Perth and Houston over October to December this year, and a 2 day “Data Expo” planned for Houston in April 2018.

Too often data managers are like the “mums of the industry – we keep it all running and we never get any recognition,” she said.

Ms Curtis quoted a CDA study which stated that data contributes 25 to 35 per cent of the business value of an E+P company. But in practise nobody ever sees this number. Data is usually either a big asset, when it helps to do something, or a big liability, when it means big costs and effort to manage or clean up.

Data managers should be seen, and should see themselves, as strategic resources who solve business problems, rather than as tactical resources, such as “people who load well logs day after week after year,” she said. The society was originally formed as the “Public Petroleum Data Model Association” in 1991, but changed its name in 2008 to reflect the growing industry recognition of data as a strategic resource, and the need for professional data managers to steward the data through its use by many groups and processes. The formal purpose is “to create a global professional community of practice for those who manage oil and gas data and information as an essential asset using a collectively developed body of knowledge.” 8

The “Me” Approach Many of the problems with corporate data management could simply be described as the “Me” approach, or people putting their personal interests, or their department’s interests, in front of the interests of the whole community, she said. For example, a data manager might be asked to do only what their immediate internal client needs, not what other people in the company or even outside stakeholders might need. This means data is prepared to meet the needs of the

digital energy journal - November - December 2017

Trudy Curtis, CEO of the Professional Petroleum Data Management Association (PPDM)

internal client but may not be left in the best condition for anyone else who might need it in future. “The “me” world sacrifices efficiency for individuality,” she said. “The “we” approach that PPDM is building with its members, balances the need for consistency and individuality”, adding that a strategic data asset should be received in trusted form, and ready for use in advanced analytics or business intelligence tools. “In this [oil] economy we can’t afford the waste that proprietary standards demand anymore.” A similar scenario is seen in government data repositories, where one department may be

Subsurface in charge of receiving and approving data, and another department who needs to work with it. If data has been accepted but then proves not fit for purpose, the accepting department is sometimes powerless to do anything to improve the situation, she said.

Standards PPDM’s other purpose is to develop international data standards that the oil and gas industry can use. Data standards govern the content, quality and format of data, and are designed so that if the standards are followed, everybody can work with it. Today, data gets a lot of ‘massaging,’ where everybody reviews and amends the data they receive before they can do their work with it. Then the data is passed on to another department, and the ‘massaging’ continues. It is a lot of work, and you end up with multiple versions of the data being circulated around the company. Data standards are intended to ensure that high quality data is available to all, fit for purpose. The problem also occurs in the operator / regulator interface, where different regulators want data in different ways, so operators are constantly massaging data for all the regulators they work with. PPDM defines a standard as a “tool which is useful in a specific situation”. For example, if you are building a data repository, you may find the PPDM data model useful. This is different to “best practises”, which could be defined as a “core of industry developed methods and expectations.” These represent knowledge and skills that every data management professional should master. Professionalism is achieved through properly applying a mixture of standards and best practises, Ms Curtis says. Agreeing on standards, and then deploying standards consistently pose different challenges. During deployment, some may revise the standard to meet their internal beliefs, while others simply want to develop their own standards. A proprietary product with a thin “standards veneer” on it is unlikely to deliver the standards promise of interoperability, accessibility and trust. As an illustration, you can see the story of international accounting standards. The first standard, the “Generally Accepted Accounting Principles” or GAAP, was developed in the US

in the 1930s. But over the decades, different versions of GAAP emerged from different countries, so we got GAAP USA, GAAP France and so on. A subsequent effort started in the 1970s to develop new International Financial Reporting Standards (IFRS); consistent implementation is a requirement for IFRS.

The data model PPDM’s flagship standard is a “data model” for exploration and production, showing how a relational database, with multiple tables, can be constructed to handle the different types of data which oil companies work with. The organisation was originally formed in 1991 to develop a standard data model for the industry. Ms Curtis notes that the data model should not be seen as an answer to every problem, and not all PPDM members use it. “It proves to be useful in many situations,” she says. Some people do not believe that the future of data storage is in relational databases at all, she said, encouraging data managers to understand the model as a collection of data rules, terminology and relationships that reflect the needs of business, rather than a software application. PPDM is currently developing a new version of the data model, which will be called PPDM 3.10. It will include standards for water management and support for hydraulically fractured wells, which tend to generate much more data than conventional onshore wells. It will also incorporate a standard “units of measure” data set, which was agreed by the Standards Leadership Council, an ‘Uber’ body for oil and gas standards bodies. It will support the “EPSG” Coordinate Reference System, which is defined by the International Association of Oil and Gas Producers (iOGP).

Standard definitions Another big area of PPDM’s work is trying to develop Rosetta Stones for common industry terms such as well, completion and kick-off. Ms Curtis made it clear that significant change management is required to adopt a new vocabulary. PPDM’s vocabularies are simple to use, easy to understand, and support a staged approach to adoption that recognizes the effort needed. Unless the industry defines foundational terms in the same way, the data generated around it, such as “well kickoff date”, will not be interoperable.

PPDM conducted a survey and found that the “well kick off date” is understood to mean just about anything from the date you start well planning to the date you start well production, and everything in between, such as when the drill bit first rotates to create the well. When you use terms which mean different things in the industry, “you think you’re being clear, but you’re not,” she said. In the US, a well is identified by the well head (at the surface) – one well head means one well. In Alberta, Canada, a well is identified by the place a wellbore connects with a reservoir, so if a wellbore connects with several reservoirs, it can count as a several ‘wells’. There is also no industry agreed definition of when exactly a well’s status is “producing” or “abandoned”, and no agreed definition on what a “well formed” well directional survey looks like. There have been well collisions, where a well is drilled into the side of another one, where subsequent investigations showed that bad data practises were the cause, she said. “Completion” is another term with different definitions in the industry – some people see it as related to the reservoir, others to a drilled wellbore, others to the equipment in the well, while others are more concerned with the obligations generated or outcomes of operations. PPDM is developing a publication called “What is a Completion” to try to resolve these mixed definitions for completions. It also has an “open data rules depository” with over 3,000 rules which can be used to ensure data quality.

Certification PPDM committees have developed a certification program for data managers, and have been working toward additional certifications. The data management certification programs cover ongoing professional development, and methods for verification of knowledge and skills. This means that companies hiring data managers will have more certainty that the person they are hiring will start with a baseline of knowledge and skills appropriate for the oil and gas industry. This is particularly important, says Ms Curtis, when consulting companies work in many disciplines and regions around the world.

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Subsurface

Make Your Own Luck

Add resistivity measurements to seismic for increased discovery success. When interpreted with seismic, resistivity information from Towed Streamer EM enables more reliable ranking and derisking of prospects. Contact us about adding EM to your seismic: [email protected] A Clearer Image | www.pgs.com/TSEM 10

digital energy journal - November - December 2017

Subsurface

1st Subsurface – developing subsurface databases

1st Subsurface Oilfield Management, a consultancy in Aberdeen, is developing subsurface databases covering producing and abandoned fields, unsanctioned discoveries, prospects and leads in all the UKCS oil and gas basins and now internationally. The databases can be used to assess drilling prospects, and find analogues for unsanctioned discoveries and producing oil and gas fields. A particular application is within the outer Moray Firth, where these databases are being used by the Outer Moray Firth Special Interest Group (OMF SIG). Here, a range of licensees have come together to generate the first sub-basin level Maximising Economic Recovery (MER) Area Plan for the UK, using the databases to assess potential, generate new opportunities and drive collaborative strategic plans. The oil and gas industry is well known for generating data, which is then forgotten, says Paul Lindop, infrastructure and commercial lead with 1st Subsurface. The databases start by bringing together all publicly available data for the basin into a single source, to make it easier to work with and look for opportunities to improve economic recovery. Where available multiple historical interpretations of the same prospect are recorded and made accessible, the user can make their own judgement, rather than have to work with the judgement of the database creator, as is often the case, Mr Lindop says. “This objectivity is highly valued by system users as is the fact that all the data gathered has an audit trail, so the user is able to validate the data point themselves.” The approach could be considered knowledge as a service, Mr Lindop says. It is similar to a Wikipedia page, where subject matter experts curate and present the most useful information about a subject in a way which is easy to work with, using multiple information sources, and continually updating everything, with 1st Subsurface acting as the curator/ moderator. Whilst the work to date has used data already publically available, 1st Subsurface are working with subscribers and other parties to release further non-commercial data to be accessed through the service. There are software tools to assess the fields, discoveries and prospects. For example you

can plot them on a range of predesigned or custom cross plots to view assumptions in context of all related data, allowing rapid comparisons to be made between opportunities being considered and all other fields and discoveries in a geologic basin. Functionality will be developed to allow inclusion of restricted data in the analytical tools. In this case, the system will allow data points to be included in the analytics, but without being able to trace back to the confidential source. Moderated by 1st Subsurface, these additional data sets are intended to enrich analysis and support better decision making, without compromising a client company’s commercial position. Subsurface data is currently available for almost 600 Producing or Decommissioned Fields, over 400 Discoveries and over 1000 Prospects and Leads in the UKCS and growing daily! The technical director of the company is Mike Cooper, former subsurface manager for Centrica and VP exploration and subsurface with DEO Petroleum. Infrastructure and commercial lead, Paul Lindop has worked with a range of companies in managing director, asset and commercial management roles. Maurice Bamford is former exploration and geoscience manager at Talisman (now Repsol-Sinopec) and EnQuest. The company also works with subject matter experts in geoscience, reservoir and petroleum engineering, production technology and commercial oil and gas issues.

Outer Moray Firth project The Outer Moray Firth (OMF) is a prolific oil and gas producing area North and East of Inverness. Around 25 oil and gas companies are active in the basin, with 79 producing fields. Recent licence round awards now make up more than 50% of the licenced acreage so it remains an area of interest across the life cycle. In recognition of this, the OMF SIG has been formed with the specific aim of generating a Strategic Area Plan – aiming to assess how

big the “MER pie” could be. It then formulates strategic plans to maximise the chance of achieving that pie. Before the oil price crash, it was common for companies to put together “joint industry projects” to deliver projects such as the OMF SIG, with staff from different companies contributing time. However, with the current market conditions, companies do not have spare staff capacity. So solution has been for 1st Subsurface to take on the bulk of the work and only drawing on the licensees for governance and subject matter expertise in workshops. The SIG members span the life cycle from Promote Licensee to Mature Asset Operator, providing a unique full spectrum set of perspectives on opportunities and barriers for MER. As with any strategic planning activity, you need two things – a clarity on the goal and an assessment of where you are. The databases the company has put together provides an assessment of where you are. For the OMF they include a wide range of subsurface data parameters on 79 producing fields, 80 unsanctioned discoveries and over 400 different prospects and lead evaluations, all available with references to their source documentation, including the interpretations behind them where available. The service should be ideal for a company considering setting up operations in the region, wanting all the information available on their computer desktops in a user-friendly format and at a competitive price, Mr Lindop says. It will help companies do more with their subsurface teams by avoiding the repeated process of finding open and context data “yet again”, and allowing them to build on this base layer of data to add genuine value and get maximum benefit from the industry’s years of cumulative experience in a basin. Further information about the Outer Moray Firth project is online at www.omfmer.uk.

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Operations

Making digitech work

Digitech equipment, such as sensors and drones, is getting cheaper, but the challenge is still working out how to get value from it. A conference session at Offshore Europe in Aberdeen looked at reducing uncertainty, risk taking and data management, with speakers from Schlumberger, AkerBP, Statoil and Wood Mackenzie tory is available and identify potential risks. Schlumberger is also looking for ways to reduce the length of time to process a seismic survey from 18 months to 2-3 months, by introducing a lot of automated steps and removing a lot of steps, he said. For its internal IT infrastructure, Schlumberger is developing its own “data lake”, working with Google, he said.

From left to right - Simon Flowers, chairman, Energy and Chief Analyst with Wood Mackenzie; Ragnhild Ulvik, vice president innovation with Statoil Global Strategy and Business Development; Dr John Lervik, founder of Cognite, working with Aker BP; Eric Abecassis, CIO of Schlumberger; Janeen Judah, president of the Society of Petroleum Engineers

Janeen Judah, president of the Society of Petroleum Engineers, chairing an Offshore Europe conference session on “Describing a Future E&P Based on Innovative Digital Solutions and Big Data,” said that “the biggest topic in the oilfield right now is about big data, I can tell you without a doubt.” “We look for big data to help us [with] opex, safety, reliability. We’re all looking for solutions.” “We’re seeing an evolution in digital technology. Sensor technology, communications everywhere, learning algorithms, Google-isation of data,” she said. But the question is how to come up with meaningful solutions for industry problems like maintenance, seismic recording, well testing, automated drilling and predictive analytics. The gradual reduction in price and increase in reliability of many sensors takes the industry to something of a “tipping point” where it becomes possible to do much more with them, she said. A lot of the visualisation technology which has recently came into the oilfield was originally developed by the computer game industry, and the industry probably would never have developed it under its own steam. Perhaps the industry needs to be more willing to take risks, or to ‘fail fast’, in Silicon Valley jargon. Ms Judah noted that US space company SpaceX saw its “first 8 or 9 rockets crash”. Ms Judah said that future workers would need a combination of traditional oil and gas domain 12

knowledge and IT skills, such as the ability to write PYTHON.

Eric Abecassis, Schlumberger Eric Abecassis, CIO of Schlumberger, said he saw the current digital technology challenge of getting to a point where machines can work by themselves, rather than just doing “simple modelling tasks”. If the first industrial revolution is about amplifying human muscle, this “fourth industrial revolution” is about amplifying the human brain, he said. The challenge is making digital tools which can handle all the uncertainty and complexity in the oil and gas industry, including with “a lot of science” and safety concerns. Schlumberger’s “big data” efforts started in around 2012. “We started to realise there is much more value in data than data has been designed for,” he said. It went on to develop systems such as the wellsite Prognostic Health Monitoring (PHM) system, to use data to try to improve the reliability of its wellsite tools. Schlumberger is organising itself in different ways, becoming less centralised, so more people can have a chance to work out how to get value from the technology. “Our future is based on more collaboration and partnership,” he said. It has developed a frac site monitoring system using a drone, where a drone follows a pre-programmed flight plan, and takes video images which can be analysed to work out what inven-

digital energy journal - November - December 2017

Mr Abecassis was asked if he could think of any examples of using data which were “top down”, trying to make software do what experts do and better support people, rather than “bottom up”, starting with data and working out how to get knowledge from it. He provided two examples of what could be considered “top down” projects. One is a project to map how information is flowing internally, to show people see how they fit into the overall knowledge chain, and who has the critical company knowledge. The second example was a system to capture what people are actually doing with the software, which could be used for later analysis. There is also some automation of tasks which are normally one by experts, such as log interpretation, he said.

Dr John Lervik, Cognite / Aker BP Dr John Lervik, founder of Cognite, a Norwegian company specialising in data handling working with AkerBP, said that the overall digitisation vision is “obvious,” with much more automation and robotics. Cognite grew out of a digitalisation project and strategy Dr Lervik was working on with Norwegian oil company AkerBP. Cognite is building a multi-layered, cloud hosted data platform for Aker BP, where the first layer

Operations is the “data lake” (making all data available on one system), the second layer is to map the data as much as possible (to time or to 3D models), and the third layer is to develop “robust” application programming interfaces, so other software can work with the mapped data. Gathering data is very important, because data processing algorithms are “worthless” if you don’t have large amounts of data to run them on, he said. Aker BP has 80,000 sensors in its infrastructure. Often sensor data “has a lot of noise and a lack of structure,” he said. “Sensor data needs to be linked to contextual data to be truly useful.” An example of mapping data to a 3D model is to map a maintenance log to the location of the item being maintained on a 3D model of the offshore structure. You can also map piping / instrumentation diagrams and historian data to the 3D model in the same way. The company has also put together a number of “use cases”, showing how people are working together with the technology to achieve a specific goal. All of the work is owned by the relevant business line, not a digitisation committee, he said. Dr Lervik had sharp words for a delegate from a well-known historian data company in the audience who was asking questions about collaboration. “You need to improve the performance of your APIs,” he said.

Statoil Ragnhild Ulvik, vice president innovation with Statoil’s Global Strategy and Business Development division, said that Statoil’s target areas for “digital competence” are improving subsurface analytics, doing more data driven operations, and optimising production and maintenance. “It is about digitisation of work processes, advanced analytics and remote control,” she said. The company is only using a small fraction of its available data, she said. “We don’t even know what we know.” It sounds simple to use new tools to take advantage of data, but if really was simple it probably would have been done already, she said. For subsurface data, Statoil is building a “data lake” which will make all the data available from

one place. Before, “we had 40 different databases - 50 different data types, not at all comparable,” she said. The disconnect between databases isn’t always apparent to the individuals running the systems, because they can only see their own database, she said. Statoil is currently aiming to get all of its data on a cloud based system, so it can all be accessible throughout the company.

Wood Mackenzie Simon Flowers, chairman, Energy and Chief Analyst with Wood Mackenzie, pointed out that the oil majors seem to be appointing more people with downstream experience as their CEOs, perhaps because they think that the industry overall might benefit from the ‘low cost’ downstream culture. The current CEOs of Shell and ExxonMobil are former downstream people, and Chevron has announced it will shortly appoint a downstream person, Michael Wirth, as its CEO. “People say the future is all about being a low cost producer and digitisation has to be part of that,” he said. Mr Flowers likes the idea of doing digital “dry runs” on workover programs, so you can practise doing something like on a computer game before you do it, and this way ensure good performance (and value from your rigs) when you do the work.

technology. “It is close to being applicable.” SPE’s Janeen Judah noted, that you can do a great deal of useful work today with a $1000 drone.

Sharing data Aker’s Dr Lervik noted that data sharing would be a big step forward. Until now, data sharing in the industry has largely been restricted to safety and security. But now people are thinking more about sharing operational data. However there could be bigger obstacles to sharing seismic data, considering the amount of money companies have invested in it, he said. SPE’s Janeen Judah noted that engineers are still spending an estimated 40 per cent of their time “finding and massaging data”, and some of these workflows will have to change. Schlumberger’s Mr Abecassis noted that companies might come up with new business models around sharing data. One audience member noted that “sharing data without meta data is a mug’s game, how do we address that?” “To get value you need to link things together,” Dr Lervik replied. “That’s a very big problem. [But] There are a lot more technologies available. I’ve been working in this area for 20 years.”

Interesting big data projects The panel was asked for examples of companies “doing interesting things with big data”.

Humility The panel was asked if the approach to digital technology is perhaps becoming more humble than during the previous decade, where there was a lot of talk of grand ideas like “digital oilfield” but not so much actually achieved. “The digital oilfield was a bit of grandiose vision,” Schlumberger’s Mr Abecassis said. “But there is a lot of incremental revolution, and it is adding up. We will get there.” “It is very important to have some vision,” said Aker BP’s Dr Lervik. “We are now running a lot of projects. [but] I still have to hear about almost anything that is not a test.” Wood Mackenzie’s Mr Flowers noted that technology has made big developments over the past 2-3 years, in particular reducing the cost of

Schlumberger’s Mr Abecassis said he knew a small start-up company which makes an app for equipment operators, providing standard work instructions, which also gathers data about how the app (and by extension, the equipment) is being used. “It is starting to read the operator,” he said. Cognite’s John Lervik said that Google is “starting to make available a lot of technologies in a standard way for low cost. For example there is a “voice interface that supports 110 languages at low cost. You can add some things for oil and gas. That’s a company which is innovating a lot.” Statoil’s Ms Ulvik said she was a big admirer of Apple. “If you need something, [often] they’ve thought of it before you,” she said.

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Operations

Disrupting and digitising our industry An Offshore Europe session “disrupting and digitising our industry,” looked at fully automated mining, new working practises, learning from manufacturing and dealing with uncertainty, with speakers from Schlumberger, Rio Tinto, Baker Hughes, OGTC, Shell Technology Ventures and Siemens The success factors with automation are having highly skilled people, a detailed concept of your operations, and “effective partnerships and governance,” he said.

Colette Cohen, OGTC

To automate your operations, you need to learn how to operate the equipment and embed it in your working methods – you have to do much more than just buy automation, he said.

Alastair Mathias

Alastair Mathias, general manager, mining automation and analytics, Rio Tinto, told the story of how Rio Tinto had introduced automated mining systems for iron ore in Australia, with staff operating remote drilling machinery and trains from an office block in the city of Perth. The mining industry has similar stresses to the oil and gas industry, in that there are shortages of people with the right skills willing to live and work in mining regions, and commodities are getting harder to find. Through remote working technology, staff can do their work from cities which are more attractive to live in. Drillers can operate more drills at once, so less manpower is needed. Currently one remote driller operates four drills, and this might be increased to eight. Automated equipment can be safer in operation than manually operated equipment, and there are other longer term health benefits, from reduced human exposure to vibration and dust. There can be less wear and tear on equipment, and machines operate within their design parameters. There is also a much clearer signal from the sensor data from automated operated equipment, which means “we can do more things with it”. The equipment manufacturers were not wholeheartedly in support of the idea, with some saying it was not in their interest to make machinery which could enable higher productivity, if it meant the customers would buy less equipment as a result, he said.

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But once you have this organisational ability, you have a strong edge on competitors, because the only way other companies can gain this ability is by going through the same multi-year learning curve. “You can’t buy operational experience,” he said. Rio Tinto is considering operating all of its drilling equipment from two or three operating centres around the world, which would enable it to “follow the sun”, with centres operating during daylight hours (so nobody is working night shifts) but operating equipment which is actually operating during the night in other parts of the world. So overnight operations in Perth could be operated from London, for example. The project got moving with an intense effort with a special group in the company, not through incremental development. The issue had been discussed in the past, but had come across all kinds of problems with hardware and software, which needed to be overcome. There was something of a lack of willingness among vendors to co-operate and build a single platform, so all the systems would integrate. “So we built it without them,” he said.

Colette Cohen, CEO of the Aberdeen based Oil and Gas Technology Centre, noted that the digitisation is now driving big changes in how companies work. In this way, the current changes are different to digital technology adoptions in the past. Oil companies have not changed the way they work much over the past 40 years, as can be seen by comparing pictures of offshore oil platforms built in 1973 (Viking Bravo) and 2013 (Cygnus Platform). The platforms look similar visually, and were designed to be operated in similar ways, by around 100 offshore staff, she said. But during the same period 1973 to 2013, the car industry has “undergone a complete revolution in design and engineering,” she said. The oil and gas industry does need a vision of where it is going, because it won’t happen by “sleepwalking into it”, she said. One vision could be to have everything remotely operated and autonomous.

The ideal system would be one where it is easy to plug and unplug different tools onto the platform, so it is easy to change for something else.

This would not necessarily mean retrofitting existing equipment, because this can be much harder than building something new to be autonomously operating, she said.

The company expected human factors – persuading operators that it was safe to operate equipment remotely – would be one of the biggest barriers, but that happened easier than expected, he said.

Companies do need to be cautious. “When we get it wrong there are company ending ramifications.” But there will have to be a little more “trying something in a different way”.

Today, people have become perhaps too comfortable with the autonomous equipment, sometimes driving in front of an autonomous truck to demonstrate that it will stop.

digital energy journal - November - December 2017

Siemens Thomas Sparks, vice president of Oil and Gas Strategy and Technology with Siemens AG, and a former head of manufacturing engineering with MTU Engines North America, said that

Operations the oil and gas industry could clearly learn more from other industries, who have been more successful introducing automation.

Thomas Sparks, vice president of Oil and Gas Strategy and Technology, Siemens

For example, one manufacturing plant in Hamburg has entirely automated their plant, and as a result increased output tenfold. A Spanish rail operator, running trains from Barcelona to Madrid, has only one late train in 2300 trips, with everything remotely monitored. Sometimes technology developed in one sector can be adopted by another. As an example Siemens has adapted a technology for scanning human bodies, which was then adopted to be used for scanning seabeds for gas leaks. The technology meant it was possible to scan the seabed four times faster than before, with a big reduction in vessel costs. Siemens’ heritage is mainly in making hardware, but it has made a big move into software, currently employing over 20,000 software developers, he said. Mr Sparks believes that “there’s a distinct possibility offshore operations will run under an entirely new business model in 2030.” Siemens is thinking about “Topside 4.0”, a fully digital operation. However it might also be good to focus on finding something where digital technology works, such as putting analytics on a LNG liquefaction train, rather than a grand vision for everything, he said. One path forward could be where large companies like Siemens develop robust open platforms, and smaller companies and customers can build apps on it. GE is doing something similar with its Predix platform, he said, or Apple with its Apple store. Mr Sparks thinks that we should not start seeing computer power as something similar to human brain power. “A human is a human, and a brain is a brain,” he said.

Schlumberger

ies can struggle financially, having to continually “justify their existence” to stay in operations.

Dr Simon Bittleston, VP of research with Schlumberger, said he is interested in “inference systems”, which can apply logical rules to the existing knowledge base and deduce new information.

Shell Technology Ventures has venture capital funds focussed on new energy (including biofuel and hydrogen). It is also setting up a digital fund.

A big recent advancement in digital systems is that they have been far more able to deal with uncertainty. Early automation systems worked by following a series of prescriptive instructions. But this made the set-up very fragile, because anything unexpected would mess everything up. The system “needed a lot of babysitting”. Dr Bittleston emphasised that automation needs a lot of sensors. A so-called “cognitive rig” needs sensors for managing the downhole system, for hoisting and rotating the drill pipe, for managing fluids, for managing associated data. Schlumberger has also introduced automation for automated steering of streamers in seismic recording. A seismic survey can involve 10 streamers being pulled behind a vessel, each 10 km long. Schlumberger uses 300 “autonomous vehicles”, or robotic boats, to keep the streamers in the right place, as water currents move them around, and track where exactly the streamers are. The data volume about streamer positioning is a quarter of the size of the seismic data, he said. It would not be possible for a human to drive all of the 300 autonomous vehicles, so they need to be controlled by computer. David White, senior technology advisor, Schlumberger, chairing the session, noted that companies will be more inclined to do something if it is easier. For example, rotary steerable drilling was very easy to introduce, because the only change was to unscrew one bit and screw in another one. But slimhole drilling (where one piece of drill pipe is pushed through the inside of another and then expanded) needed a completely new rig to do, so was a much bigger project to install.

Shell Peter van Giessel, senior venture principal with Shell Technology Ventures, said that it isn’t obvious what business model is best suited to achieving the ‘moonshot’ step change improvements which Shell is looking for. For example, oil and gas service companies are “not known for their speed of innovation.” But start-up compan-

Shell is particularly interested in hybrid business models, for example around “connected mobility”. As an example, Shell “sells more coffee than Starbucks” in its petrol stations around the world, and there may be business opportunities there. An interesting investment is Glasspoint, which builds systems to make steam from solar energy, with curved mirrors inside a greenhouse. Shell uses the technology to make steam in Oman, which is injected into the reservoir to improve recovery. Drilling automation is an interesting area for Shell. A challenge is that the company does not buy or operate drilling technology – yet it stands to benefit the most. It would be helpful if drilling automation technology could be tested and developed in onshore drilling projects before taking it offshore, but there is not much of a business case for using it onshore, where the costs are lower, he said.

Baker Hughes Zvonimir Djerfi, president and CEO Europe of Baker Hughes, said he is seeing companies are working in very different collaborative ways, for example with drilling companies paying a service company based on the reliability and availability of equipment. Companies are looking for ways to manage high capital expenditures as an operational expense, he said. Companies are also signing much longer term contracts, for example a $700m contract over 10 years to provide blow out preventers to a drilling company. Baker Hughes is helping one of its customers simplify what is needed to develop a field, he said. Its parent company GE is involved in many industry sectors, including aviation, healthcare, transportation, power, and some are more advanced with digital technology than others.

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Operations

AkerBP – a new business model for oil and gas AkerBP, the company formed from the merger of BP Norge and DNO, is developing a new business model for oil and gas operations, based on a different type of relationship with suppliers AkerBP, a Norwegian oil and gas company formed from the merger of BP Norge (Norway) and DNO, is developing and testing a new business model for oil and gas operations, based on longer term and deeper relationships with suppliers.

The big test of a supplier-operate alliance is when you have a problem to resolve, he said. “You need to be able to admit when you make a mistake.” It is important for top management to be involved in both the negotiations and operations, he said.

The company is called AkerBP because Aker Capital, part of Norwegian holding company Aker Group, owns 40 per cent of the company, through its previous holding in DNO. The merger is seen by BP senior management, among others, as combining the strengths of both companies, which it sees as BP’s “long experience and technical expertise in the basin,” and DNO’s “streamlined business model”. Øyvind Eriksen, chairman of Aker BP, explained how the business model works, in a conference session at Offshore Europe event in Aberdeen in September, “New Business Models to Address Mature Basin Challenges.” Suppliers typically account for 85 to 90 per cent of an oil company’s total costs, Mr Eriksen said. So when there is a need to reduce overall costs, suppliers’ costs are a big target. But rather than achieve these cost reductions through negotiation and bullying, as it is usually done, AkerBP tries to find ways to reward suppliers for finding ways to reduce costs. One approach is to substitute traditional procurement methods with long term supplier alliances. Aker BP agrees contracts for 5 years, with an option for both parties to continue for another 5 years. This gives suppliers a better understanding of how much business they will get over future years, and so enables them to plan their own spending more efficiently. It also facilitates continuous improvement, as companies work together over longer periods and get better at it. The company is also reducing the number of suppliers it works with, a move which has led to improvements in productivity, as it has in other industries, he said.

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Sharing Both operators and suppliers can reduce their costs through sharing data, working together on standards, and setting up common business vehicles, he said. Øyvind Eriksen, Chairman of Aker BP

The company puts together teams to work on projects including both operator and suppliers, and puts the best person in charge of the project, regardless of whether they are employed by Aker BP or the supplier. The commercial terms are arranged based on the suppliers’ net costs of providing the service, and a fixed margin to the supplier. There is also an incentive program based on the success criteria for the whole project (usually total cost and start date, if it is construction). Suppliers can get a share in Aker’s benefits, if the project does better than expected, and take a share in AkerBP’s additional costs, if the project does worse than expected. But the hit to the supplier is capped, because Aker BP does not think it is in its interests to “see a supplier go belly up.” As a result of these kinds of arrangements, the drilling efficiency has been more than doubled, the engineering hours have cut in half, and execution time has been cut, he said. The operator-supplier alliances proved to be easy to design in theory but much harder to make work in practise. “It boils down to behaviour,” he said. For the model to work, suppliers need to share their own cost data, so everybody can see the margin the supplier is making. Some companies showed a reluctance to do this, he said.

digital energy journal - November - December 2017

As an example, the Norwegian banking industry developed common digital tools which many banks would use, and as a result improved productivity by 2.5 times, he said. “More can be achieved if we start sharing data,” he said. “Operations, maintenance, supplier qualification and decommissioning. Most of the data can be shared if you want to.” Oil companies mainly compete by getting access to better acreage. They are not usually competing in terms of how they operate technically. So there should not be so much reluctance to share technical data between operators, or to work on common standards, he said. Examples of useful standards are the International Association of Oil and Gas producers (OGP) work to standardise technologies such as subsea Christmas trees, and the NORSOK standards for technical specifications in contracts. Companies might also collaborate better in decommissioning, setting up a special purpose business vehicle to do multiple projects, rather than the current fragmented and operator specific approach. More sharing of experiences can help all companies to continuously improve, leading to safer operations with better reliability.

Operations

McKinsey, Baker Hughes, Siccar Point Energy The ‘new business models’ session at Offshore Europe also featured McKinsey on the most important building blocks for an oil and gas company, Baker Hughes on a shift to collaborative mind-set, and Siccar Point Energy on the value proposition of the North Sea Dan Cole, Senior Expert, McKinsey & Co, said that according to McKinsey’s analysis, the key characteristics of a successful company are its ability to respond quickly, and its resilience. “The companies that get both massively outperform everybody else,” he said.

operations do not become overwhelmingly complex as they get bigger. Pace of work is important because some operators can do tasks like well interventions faster than others. For digital, Mr Cole sees analytics as a way to “solve problems which humans can’t. If we can find machines to help we can go a lot further.” When asked about the best training universities can provide bearing this in mind, Mr Cole replied that one of the important skills universities train people for is being able to deal with ambiguity, being able to solve problems and communication skills.

Dan Cole, Senior Expert, McKinsey & Co.

By ability to respond quickly, Mr Cole means the company is flexible, gives autonomy to people in the front line, and is able to handle a good general pace of change. By resilience, he means that the company has good central co-ordination, has standardised working methods, and good leadership. To some extent, these factors are opposites, he said. But then there are quite a few companies which master both of them. As an example we see that Amazon is able to react very quickly to developments, but also has a stable backbone. A common weakness of oil and gas companies is that they are not very good at killing off projects which aren’t working, he said. Mr Cole sees five important building blocks for a good oil and gas company as the operating model, managing physical scale, pace of work, use of digital, and innovative partnerships.

When asked how the industry can ensure changes are sustainable, Mr Cole said he thought maintaining better relationships with suppliers “is the most important thing”.

Chris Jones, Baker Hughes Chris Jones, Europe Oilfield Services Leader, Baker Hughes, said he had observed a shift in the industry to a more collaborative mindset, with companies forming longer term alliances and developing new business models, rather than companies bullying each other out of business in an “only the most desperate survive” model.

structure was put together with the operator and suppliers where they would all win or lose together. “The result was a step change in performance,” he said, and also a paper was presented on it at OTC in May 2017. A third example is a very complicated, mature field in Malaysia, which wanted to get its recovery factor from the mid 20s to 50s. A 23 year alliance was put together between the operator and suppliers, with targets based on incremental production. Mr Jones noted that while there has been a blossoming around partnership, there hasn’t yet been much sharing of information in the industry. Every company wants to be in the “top quartile”, but there is a feeling that if you share the reasons you are in the top quartile with other suppliers, they can be as good as you can, and you are no longer top quartile.

Siccar Point Energy Jonathan Roger, CEO, Siccar Point Energy, said he saw a very strong value proposition in the North Sea, in terms of the amount of opportunities and limited competition (in terms of other companies wanting to invest).

The test of a business model should be whether it can drive efficiency gains, or enable additional activity, or unlock incremental value, he said. Mr Jones gave three examples of companies working collaboratively.

The “operating model” is about how the company sets up its work, with people and tasks, and strategies about how to use assets.

One was a mature well which would benefit from well stimulation, but there was a marginal business case for it. But a well stimulation supplier had spare capacity to do the job, and accepted part of the risk of the success of the project, by having a payment scheme linked to the amount of increased production achieved.

Managing physical scale is about keeping large operations simple, or ensuring that your

Another second example was on Johan Sverdrup field in Norway, where a contracting

Jonathan Roger, CEO, Siccar Point Energy

Siccar Point Energy is a new North Sea operator backed by private equity company Blackstone Energy Partners. It already has interests in “3 of the largest UK fields by remaining reserves - Schiehallion, Mariner and Rosebank,” he said. Mr Roger noted that people in the supply chain “want to feel they are adding value and contributing, not being dictated to.”

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Aberdeen’s Oil and Gas Technology Centre Aberdeen’s Oil and Gas Technology Centre (OGTC), which opened in Feb 2017 with £180m government funding, is already working on 21 projects, trying to identify which technologies can best solve the industry’s problems Aberdeen’s Oil and Gas Technology Centre (OGTC), which opened in February 2017, already has 21 projects on the go and considering a further 100, with a purpose of trying to identify and develop technologies which can best solve the industry’s problems. Its technology goals have been set by the Technology Leadership Board, a body with senior representation from across the industry and government. OGTC has £180m funding as part of the “Aberdeen City Region Deal”, agreed between the UK government and the Scottish government. The money can be invested in technology on a ‘match funding’ basis, which means that it will only invest if industry is also willing to invest the same amount. The technology development is organised around specific challenges of monitoring asset integrity, improving well construction, improving decommissioning, digitalisation and getting “small pools” (small reservoirs) into production. OGTC is currently “more at a scoping level”, said Colette Cohen, CEO of OGTC, looking for technology around its target areas, including asset integrity, next generation well construction, small pools, and plugging and abandonment of wells, to reduce decommissioning costs by 50 per cent. In asset integrity, “there’s a lot of technology out there which hasn’t been adopted,” she said, particularly non-intrusive technology (using radar or microwaves) to get a sense of asset condition, rather than “intrusive” technology where you have to do some damage to see something (such as looking for corrosion under insulation). The non-intrusive technology has to prove it is as good as intrusive. “We are trying to eliminate shutdowns based on asset integrity.” OGTC aims to provide a ‘safe haven’ for operators to partner with small innovative companies and try things out, she said. OGTC is keen to bring in expertise from other sources, rather than the “normal people who address our problems,” she said. For example, a company developed a technology radar idea which originally came from a zoologist. 18

The technology must be focussed on improving the existing business, in particular improving offshore asset integrity management, and “what is going to help us find and develop new resources.” One specific technology request was a means of separating oil and water at the subsurface, so you only bring oil to the surface, rather than oil and water, she said.

From left to right: Greta Lydecker, managing director of Chevron Upstream Europe; Andy Samuel chief executive of the Oil and Gas Authority (UK); Colette Cohen, CEO of OGTC;

Ms Cohen was asked how companies should best “tame the beast” of data, because so many companies are drowning in it. She replied that digitalisation and big data are different. Digitalisation could be defined as “taking data into the decision making.” “That’s what we don’t do. We are the largest gatherer of data and the poorest user,” she said. When asked what she thought the industry would look like in 20-30 years, Ms Cohen replied, “Nobody can answer this. I would like to see existing facilities, which have the potential, still in operation. I would like to see decommissioning what we don’t need. I would like to see the next generation of operations unmanned and subsea with hi-tech work on shore.” If you are involved in developing new technology, Ms Cohen’s advice is “stop thinking about what it does, tell me what it does for me.” People say “it does A B and C” and we say “what does it mean?” The technology will probably need to solve a specific problem the industry has in order to get implemented.

Greta Lydecker Greta Lydecker, managing director of Chevron Upstream Europe, emphasised at an OGTC Offshore Europe event that having a close tie between technology and business needs is critical.

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Chevron has learned about the importance of developing technology as a team. Some people are good at solving problems, some people are good at maths. “It’s rare you find someone who can do it all,” she said. As an example of how the industry is working with real time data, Ms Lydecker said she previously worked on an oilfield which did continuous analysis about whether the revenues from production from each well justified the cost of disposal of the water which came associated with production, and if it didn’t, the well was shut in. That calculation and shutting in could be done in real time from an integrated operations centre. It was also possible to restart the well if the oil price increased and the calculation result changed. Chevron sees technology “as an enabler not a cost,” she said.

Andy Samuel Andy Samuel chief executive of the Oil and Gas Authority, and a board member of OGTC, said at an OGTC event that it has asked operators about their technology plans, and the results are varied. Some are doing a good job with technology, others appear to be in a “race to be second,” and some are “not in the game,” he said. OGA has government powers to force companies to adopt technology, but “I don’t think we’ll need to [use them],” he said. Mr Samuel said that OGA is currently preparing a document which will show what kind of technologies it thinks would be most beneficial in exploration and production, at specific problems new technology might be able to solve. It is working together with operators

Operations to write it. It contains “no huge surprises,” he said.

Qatar, and a technical consulting manager with Schlumberger.

identifying and screening innovations, trying to turn technology specifics into solutions.”

“If you have something that is going to work and you can prove it, talk to us, we can talk operators into using it,” he said.

OGTC’s digital goals are to improve plant uptime, increase production by at least 2-5 per cent, help prevent the next accident, and reduce costs by 10 per cent. It wants to support remote management, and help reduce operating costs.

Mr Ashley sees the challenges in the digital area as being able to visualise and integrate large amounts of data, and integrating business processes. Also the industry is “not very good at picking up opportunities,” he said.

Areas of focus include improving supply chain management, artificial intelligence on subsurface data, digitally enabled workers (which can include digitally enabled processes, tablets and wearable computers). Also developing “smart facilities”, for example with condition based monitoring and digital twins (a digital ‘copy’ of the real thing).

When it comes to getting value from data, “technology is almost the easy bit,” he said. “New technologies can be so transformative you need a new commercial model – and that’s very difficult in our regulatory environment to move forward.”

Digital Stephen Ashley, digital transformation Solution Centre Manager with OGTC, was appointed in July 2017 to lead a team focussed in identifying, developing and deploying advanced and integrated digital solutions. He was previously CIO for Maersk Oil in

The word ‘digital’ can incorporate anything from drones to sensors or virtual reality. “We work on any of these things that will have an impact on the industry and the outcome,” he said.

Stephen Ashley, digital transformation Solution Centre Manager, OGTC

The “industry is not particularly good at identifying opportunities,” he said. “We are pretty good at innovating, but not very good at rapidly prototyping and pushing it through. That’s where we [OGTC] play a key role, rapidly

One challenge with digital technologies is that it isn’t immediately clear what input leads to what output, particularly with production and uptime. So the investment case needs to be based on a willingness to try new things, rather than looking for a clear ROI. “We’re looking to develop roadmaps that take us to a vision of what to develop at the end of the day, looking at things with an immediate impact, looking for technologies that will transform the industries.”

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Peterson’s “VOR” – the Google Alexa of logistics Logistics company Peterson, together with software company Streamba, is developing a logistics system which aims to provide much better access to information about offshore shipments Logistics company Peterson, which specialises in the energy industry, is working together with software company Streamba to develop a logistics software system called “Vor” which provides much richer information about logistics shipments, including the ability to interrogate the system using voice commands similar to Google’s Alexa. Peterson is a part owner of Streamba and its main financial backer. The software product, “Vor”, is named after the goddess of wisdom in Norse mythology. The aim is to provide easy access to as much information as possible, so that customers, such as logistics managers and offshore installation managers, do not need to make phone calls to find out what is going on, says Steven Calder, director of Streamba.

Oil and gas companies are used to not knowing when a certain item will arrive until they see it arrive, Mr Calder says.

shore workers who want to know when something is arriving, without having to wash their hands and remove gloves so they can use a PC.

So far, 2 oil majors are using the system for their global operation, he says.

The system also incorporates real time images, for example from a camera on the vessel, which can let you see the cargo the vessel is carrying, rather than have to take the computer systems’ word for it.

As well as data from the logistics software systems, the software provides additional data which might be helpful, such as vessel Automatic Identification System (AIS) data so you can see the current location of the vessel delivering your supplies, or relevant weather information, for example that a thunderstorm is forecast for the anticipated time the vessel will be unloading cargo. You can interrogate the software with voice commands, for example asking where a certain shipment is, or booking another shipment. This could prove very useful for (for example) off-

Streamba is developing technology to automatically scan images looking for data which might be useful in the tracking system, for example a container number. The system might also make it easier to identify ways to share vessel space between companies, if one company can use a camera image to notice a vessel is about to sail with spare deck space.

Bureau Veritas’ plans for the North Sea Bureau Veritas, a company specialising in testing, inspection and certification in the marine and offshore industry, is planning to build its business in the North Sea, looking to make acquisitions and build its position in decommissioning, says Paul Schrieve, CEO for North Sea Operations with Bureau Veritas. In decommissioning, Bureau Veritas aims to be a “complete compliance partner” to companies, helping them ensure what they do is in compliance with regulation.

It typically takes a “few weeks” to build the models, bringing in all the data you have. Then the model can be kept up to date as new data is available.

BV also produces its own ass “Veristar AIMS” [asset integrity management system] which can be used to manage asset integrity, doing data analysis.

It is aiming to digitise its classification activities, and has developed a digital asset integrity management system (AIMS) together with software company Dassault Systèmes, so all the information about an asset is available all together. Both BV and Dassault are French. “We believe their modelling technology is one of the leading ones in the market,” Mr Schrieve says.

Dassault’s technology can be used directly by BV’s asset integrity specialists, who can run different models and simulations to help ensure that what is being operated is fit for purpose. It helps companies to focus on what they need to pay attention to.

For smaller companies, BV offers services to look after the models and do data interpretation itself. BV has 3 or 4 installations which cover FPSO hulls.

$2295 intrinsically safe tablet from Aegex Aegex Technologies, a company based in Atlanta, Georgia, has developed an intrinsically safe tablet computer which can be used offshore It is globally certified to ATEX/IECEx Zone 1 and Class I, II and III Division 1, which means that it can be used in the “Most hazardous zones of explosive environments,” says Thomas Ventulett, CEO. It has been tested in a US facility that trains emergency services personnel in realistic disaster scenarios. 20

Aegex Technologies envisages that the tablet could lead to digital technologies being used in entirely new ways offshore. As part of an “Internet of Things platform for hazardous locations,” the tablet can work in conjunction with other intrinsically safe sensors using artificial intelligence to “learn” and improve processes in offshore operations.

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The tablet is currently being used for entering data and photos from the field, data communications, and supporting inspection, maintenance, and inventory management. Data can be entered directly onto the tablet by field workers, so no need to write things down and enter them in the computer later.

Operations The tablet has a 10.1 inch high density (HD) screen, a battery covering 12 hours web browsing, 4 GB RAM, GPS, Windows 10 Pro software, video cameras on front and back, microphones, speakers, accelerometers, gyroscope and light sensor.

Thomas Ventulett, CEO of Aegex

It could also be used to work with data from sensors on field equipment sent wirelessly, for example to run analytics or view the data within apps. It could also start a business ecosystem of app development, because there are many software tools which might help offshore workers better engage with their equipment.

One challenge when building the device was ensuring it met all of the different explosion proof standards – there are small differences between all of the standards and regulations in different countries. Designing the device to be intrinsically safe basically means ensuring that no part of the device ever gets hot enough to cause a spark. But at the same time you need to make sure that battery life is not compromised, Mr Ventulett says.

The tablet was also designed with minimum weight, so it is easy to carry around. Oil and gas companies might also be interested in using the tablet in environments where there is no explosion proof requirement, but where there is a possibility of a gas leak. The company’s design and development team is based in Hungary and the US. It has resellers and distributors worldwide who are selling the Aegex tablet in almost 50 countries. The recommended retail price for the device, including Windows 10 Professional software, is $2295. Aegex is also developing intrinsically safe gas sensors, which will be able to sense more than 30 different types of gases.

ABB – providing production data through cloud analytics Power and automation company ABB has developed ABB Ability, including a cloud based tool to provide insights into production and equipment operations Power and automation company ABB has developed ABB Ability, a cloud based system to provide insights into oil and gas production and equipment operations.

and electrification, plant performance, asset management / condition monitoring, well flow assurance and production optimisation, and digital projects execution.

For example, the top level dashboard can show your key performance indicators for production, then you can drill down to get more details.

The software can be hosted on the cloud (Microsoft Azure), or it can be run from customer’s premises. It can work onshore or offshore.

The dashboard is designed to provide different ‘views’ into the data, customised to the needs of different roles, and the ability for customers to ‘drill down’ to find out more. So everybody from CEO-level executives to maintenance teams on production sites can see the same data.

ABB designs the data views around 4 “levels”, where level 1 is reviewing data from a device / equipment, level 2 is process, level 3 looks at plant level and level 4 is an enterprise wide view for executives.

It can cover multiple domains including automation, electrical, instrumentation and telecommunications equipment. ABB’s digital offering for oil and gas takes 6 particular challenges (identified by industry) into consideration – safety and alarm management, power management

Every user can configure the view to what they want. They can set up performance indicators and other measures to show what they want.

ABB says that this is the first time that the analytical insights from different systems have been brought together into a single dashboard view. Before now it was only possible to monitor the condition of one device, process or plant area at a time.

Using ABB Ability to get insights into production

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Operations Ultimately it should help companies to improve production and maintenance, and optimise processes, leading to a leaner organisation driven by data.

Gathering data In the way the system gathers data, ABB sees it as combining conventional “information technology” to the “operational technology”, or control systems environment, says Trygve Harvei, digital technologies at ABB, and former principal scientist in ABB corporate research. But the data is also gathered with a reliability level normally associated with operational technology, where ABB is most commonly known. Similarly, data is presented clearly so it can be worked with minimum effort, as modern control system displays usually are. Don’t expect any pop-up windows or adverts on the screen. But using “information technology,” ABB can get the data, deploy analytics and visualise, much easier than before, Mr Harvei says. “Our take on it is to make services as straightforward as possible. Behind the scenes, there is complex data work going on, for example sometimes data from different sources needs to be gathered together in an intermediate ‘sta-

ging’ area, sometimes involving ‘extract / transform / load’ type operations. Sometimes the data communication from multiple devices needs to be co-ordinated, or “orchestrated”. There might need to be connections with other cloud services, or enterprise software such as SAP. There are many ‘smart devices’ and data subsystems involved.

how a certain compressor is performing by looking through a range of different data. It would be possible for production engineers to develop their own tools, or use tools provided as “apps” made by other companies.

Data ownership

Production engineers can run “what ifs”, using different apps – what might happen if this valve is turned, and should you do it now.

For many years, customers have been wary of putting equipment data onto cloud systems, but the improvements in security, and assurances about data ownership, mean these concerns are going away, Mr Harvei says.

Putting the various dashboards and interfaces together for different job functions can be done by ABB staff, with their knowledge of numerous industry processes, or by an operating companies domain experts themselves.

ABB’s policy is that the customers of equipment own data and the right to analyse it. This is different to some other equipment vendors, which demand to have the sole right to gather and store data, he says.

Mr Harvei looks at the software capabilities in terms of ‘first order’ and ‘second order’, where first order means asking what happens if something happens, second order is bringing in statistics and machine learning and building models.

A library of tools

You can also make annotations and flags in the digital system, to say what you have done which might be relevant to someone looking at that part of the system next time.

The ABB Ability software can work with a range of different apps for working with different types of data, which can be made available via the Microsoft Azure platform. For example, tools to understand

Data from any third party system can be brought in.

Akselos – building 3D models of asset structure Akselos, a Swiss-US company, is getting traction in the oil and gas industry for its technology able to perform very fast “finite element” strength analysis of entire offshore assets and put the data into a 3D model which engineers can work with Akselos, a company based in Lausanne (Switzerland) and Boston (US), is gaining traction in the oil and gas industry with its technology able to perform very fast “finite element analysis” of the structural condition of entire offshore asset, and present the data in a 3D model, to make it easier for engineers to work with. Further the FEA models can be tuned ensuring to mirror the physical structural behaviours by performing operational modal analysis based on data from a few sensors on the offshore asset. It can be used to understand whether current operations are safe, and how long you will be able to safely operate before needing to decommission (remaining fatigue life). For

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terms of the asset’s likelihood to collapse under its current stresses and absorbed fatigue. If the margin is big enough, you can continue operating. You can also predict how long you will be able to operate for by seeing the trends. Further, the FEA results will provide an enhanced basis for optimisation of inspection intervals and thereby reducing opex cost. Thomas Leurent, CEO of Akselos

example, you can see if you should decommission after 2 years, or might get another 20 years out of the asset. In more detail, the system enables engineers to make a much better assessment of how safe operating margins you have in

digital energy journal - November - December 2017

The company sees a big potential market in the North Sea, where “over 50 per cent of platforms are at the end of their design life, in very harsh conditions,” says Thomas Leurent, CEO of Akselos. The company recently delivered an FPSO model to a customer, who said it is what

Operations he has been waiting for, for 25 years, Mr Leurent said. The company was incorporated in 2012, and also works in the power, mining and automotive sectors. Jens Peter Riber, a former senior director at Maersk Oil, operations, and head of the technical department, is on the advisory board of Akselos.

Finite element analysis The basic idea of “finite element analysis” is to study the forces on a tiny piece of the material, and whether it is likely to deform or change shape under those stresses – and then add it up for the entire material. An asset is not safe to operate if there is a reasonable likelihood that a critical part of the structure is likely to deform/collapse under its current stresses. To work this out, you need to use data for individual components of the asset, together with a model of the whole asset. Then by understanding the likelihood of the asset to deform under its current stresses, you can make an assessment of whether the asset is safe to operate today, and how long it might be safe to operate it for. The technology is based on patented technology developed through 15 years of research at Massachusetts Institute of Technology (MIT), looking for less expensive and faster ways to do the modelling and solving the FE-analyses. It developed algorithmic techniques to do the calculations and build a simulation 1,000 times faster than anything else on the market, the company claims. The input data is the initial asset design, supported by whatever condition monitoring data is available, such as corrosion measurements, current steel thickness measurements, cracks, flow rates through pipes, vibration and temperature. The computer system builds a 3D model of the asset in its current condition, which could be considered a “digital twin” of the asset. The company uses the term “digital guardian”.

Detailed condition-based model of hull using Akselos software

As more data becomes available from more sensors and inspections, it can be fed into the model to continuously “tune” and improve it. Ultimately, with great sensor data and continuous calculations, it should be possible to trust the digital model as a version of the actual thing, providing information about the current condition of any part of the actual asset.

ogy development got a helping hand from an “Innovation” Grant from the Deshpande Center at MIT in 2011 David Knezevic, the current CTO of Akselos, worked in Prof Patera’s research team, after completing a PhD at the University of Oxford on computational simulations with new numerical methods and supercomputing.

A 3D model can be a basis to ‘hang’ data on – and help you to understand it. In other words, the model brings structure to the data.

Thomas Leurent, the CEO of Akselos, also worked with Professor Patera at MIT while studying mechanical engineering, then went on to work in Credit Suisse as a former quantitative portfolio manager before returning to work with the technology.

It makes it much easier for a human brain (the relevant technical engineer) to work with all of the available data about the asset.

Eurostars

A 3D model could be built of an asset of any size – such as a car, bridge, production platform or even a space station.

Faster equations The ‘secret sauce’ at the heart of the system is the ability to process equations faster. The finite element analysis equations usually end up as boundary value problems for partial differential equations. In mathematical terms, the method yields approximate values of the unknowns at discrete number of points over the domain. It then uses methods from the calculus of variations to approximate a solution by minimizing an associated error function. The research to develop the technology was led by Prof A T Patera at MIT. The technol-

In July 2017 a joint industry project led by Akselos and LICengineering, a Danish design and consultancy company received funding under the EU “Eurostars” scheme. Shell is also participating. There is room for two further operators to participate in this project at a “significantly reduced price,” the company says. The project team will start by making a ‘digital twin’ of one of Shell’s assets in the Southern North Sea. In the first year of the project, members will receive a condition based model of selected assets, which they can use to analyse structural integrity in high levels of detail. In the second year, Akselos promises to combine the model with sensor data, so operators can monitor the health of their asset in real time.

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