Discussing the future of oil and gas technology at the ITF Technology Showcasein Aberdeen on March 1, 2017

How the industry is becoming more expert centric

A new way to measure density deviation

An App Store with tools to improve production

Experiences as ‘embedded IT’ in an oil company production team

Getting small pools into production

Where BP is now with digital technology

April - May 2017 Issue 66

Official publication of Finding Petroleum

From left to right:

Gunther Newcombe, director of operations, Oil and Gas Authority; Dr Geoff McGrath, chief innovation officer, McLaren Applied Technologies; Dr Geoff Nesbitt, group head technology strategy, Petrofac; Josh Valman, CEO, RPD International; Colette Cohen, chief executive officer, Oil & Gas Technology Centre; Greta Lydecker, managing director, Chevron Upstream Europe; Willie Reid, Director, Strathclyde Oil and Gas Institute and Patrick O’Brien, chief executive, ITF.

DEJ April 2017.indd 1 31/03/2017 12:30

digital energy journal - November 2016

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Events 2017

Finding Petroleum Opportunities In Iran / Middle East London, 16 May 2017

Reservoir Exploitation & Digital London, 5-6 June 2017

Transforming Offshore Operations - with a New Digital Approach Aberdeen, June 20 2017

Decommissioning - the D word! London, June 23 2017

Finding Oil and Gas in Sub Saharan Africa London, Sept 19, 2017

Connecting subsurface data with E+P expertise Kuala Lumpur, Oct 3, 2017

Transforming offshore operations with digital technology Kuala Lumpur, Oct 4, 2017

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Events 2017

Leaders

3

When Peter Zornio of Emerson and Judson Jacobs, managing director of IHS Markit’s Upstream Group, were in London recently, we had a discussion with them about how they see the oil and gas industry becoming more expert centric and human centric.

Automation companies like Emerson are taking much more effort to make their products ‘user friendly’, in particular by having a certain customer in mind who will use them, to the point of giving the customer a name in the product develop-ment process.

And Judson Jacobs, one of the world’s top oil and gas digital technology consultants, is observing that companies are making much more effort to make more value out of their most valuable experts, including having experts on specialist areas giving support to a range of different projects.

This is similar to how a heart surgeon might look after hundreds of patients at once, giving each of them a few minutes of her time, looking through the various data (which has been gathered by other professionals) and making a judgement.

Also automation and service com-panies such as Emerson are in-creasingly being trusted by large oil companies to provide outsource services to monitor

large plant infra-structure, as Emer-

son does for Shell’s “Prelude” floating LNG vessel.

Mr Jacobs and Mr Zornio were in London in January 2017 to run an afternoon event as mini-version of CERA’s “CERAWeek” conference.

Emerson is one of the main sponsors of CERAWeek.

This year CERAWeek was held in Hous-ton on March 6-10, and speakers include CEOs, presidents and chairmen of BP, Petrobras, Statoil, Chesapeake Energy Corporation, Hess Corporation, Pioneer Natural Resources, Occidental Petroleum, ConocoPhillips, ENI, PETRONAS, Gaz-prom, Shell, TOTAL. Also the VP of the European Commission Energy Union, the Saudi Arabia minister of energy, secretary general of OPEC will be present.

CERA is keen that the oil and gas industry is able to learn from some of the leaders in the consumer sector through its CERAWeek event. The key-note talk was from Peter Thiel, one of the key figures and ‘disrupters’ of Silicon Valley, one of the founders of PayPal and the first outside investor in Facebook. Last year, the CTO of Tesla, JB Straubel was a keynote speaker. One of his key messages, Mr Jacobs said, was that “innovation is painful”.

Emerson and human centric design

In terms of how systems are designed, Emerson got interested in “human centric design” 8 years ago, Mr Zornio says, when the company was trying to work out what the “next big thing” would be. It decided to place a big emphasis on making tech-nology which is “usable and human,” he says.

The business benefit for Emerson is that it can differentiate its products from com-petitors in the market through ease of use.

How the industry is becoming more expert centric – Emerson and CERA

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Cover image: discussing the future of oil and gas technology at the ITF Technology Showcase in Aberdeen on March 1, 2017 Left to right: Gunther Newcombe, director of operations, Oil and Gas Authority; Dr Geoff Mc-Grath, chief innovation officer, McLaren Applied Technologies; Dr Geoff Nesbitt, group head technology strategy, Petrofac; Josh Valman, CEO, RPD International; Colette Cohen, chief execu-tive officer, Oil & Gas Technology Centre; Greta Lydecker, managing director, Chevron Upstream Europe; Willie Reid, Director, Strathclyde Oil and Gas Institute and Patrick O’Brien, chief executive, ITF.

Peter Zornio

We discussed with Peter Zornio, chief strategic officer at Emerson Automation Solutions, and Judson Jacobs, director of oil and gas technology with CERA, how the industry is becoming more expert and human centric

Judson Jacobs

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digital energy journal - April - May 2017 4

LeadersEmerson will often have a clear person in mind who they are building the systems for, and think about what this person might need to do, perhaps what level of education of technical competence they might have.

It might consider what proportion of their working day they will spend with the product, and how the product fits with their working day, so what inclination they might have to work out how to use it in depth.

Sometimes Emerson will give this person a name, so they can “include” the person in their product development discussions, he said.

Achieving user friendliness can be much eas-ier if the system is being used by someone to achieve a specific goal or task, Mr Zornio says. The broader the scope of what the prod-uct might be used to do, the harder achieving user friendliness is.

An important factor is to minimise the amount of functionality. When building the products, engineers can be tempted to add in more fea-tures, and it can be hard to stop them, he says. Often the people building the products have much more attachment to them than the people using them ever will, and that gives them a different perspective. One person’s useful extra function is clutter to someone else.

At Emerson’s annual users’ conference, there is always a big section dedicated to hu-man-centered design, and it is often one of the most popular sessions, he says.

Sometimes Emerson gives customers a prod-uct with no instructions, to see if they can work out how to use it.

Judson Jacobs - corporate expertise management

Judson Jacobs says that in his work under-standing technology trends in the oil and gas industry, he has observed that many large companies are making big re-organisations to try to make the most out of their expertise.

Mr Jacobs spends much of his time inter-viewing senior oil and gas people around the world about how they are using or imple-menting digital technology, and the results are compiled into CERA’s specialist publi-cations. He observes that companies are making a shift away from developing digital technol-

ogy in house to working with third parties.Some of the ‘digital oilfield’ platforms de-veloped within international oil companies have quietly fallen by the wayside, he says.

However, oil companies recognise that they usually have much better domain experts (such as water flood engineers) than the oil service companies do. So if the digital tech-nology requires specialist algorithms for this domain, the oil company will be better off de-veloping these with its in-house experts.

That way, the oil company is differentiating itself among other oil companies through the capability of its algorithms, he says. It is also a way for experts to “work” on multiple pro-jects at once, if they are providing their algo-rithms rather than their personal work.

Moving stuff to the experts

One trend which both Mr Zornio and Mr Ja-cobs observe is for companies to be getting far more comfortable with the idea of letting another company’s experts run something for them.

The set-up is a little like in hospitals, where you might have several people collecting dif-ferent kinds of data about patients, which is all collated, for an expert specialist who will spend a few minutes looking at it and making a decision.

As an example, Emerson serves as main automation contractor on Shell’s “Prelude” floating liquefied natural gas facility. On an ongoing basis it will provide equipment mon-itoring, diagnostic services, spares support, and maintenance for the facility’s control and safety systems, as well as thousands of instru-ments and valves.

Two expert Emerson engineers will work with Shell staff, remotely monitoring the fa-cility’s automation from Shell’s operations centre in Perth, Australia.

This centre will have a “Collaborative Work Environment” where the Emerson team, working together with Shell specialists, will detect potential concerns leveraging the sensor network throughout the facility, and identify corrective actions, to manage main-tenance proactively. They will also arrange for delivery of any required equipment to the facility.

Another commonly quoted example is GE, which runs centres where it monitors subsea equipment and turbines on behalf of its cus-

tomers.

“That’s a business change, trusting an outside partner,” Mr Jacobs says.

Oil companies are also re-organising inter-nally, so they can have lighter asset teams dedicated to work on each project, and then the company’s top specialists can spread their work around different projects, Mr Jacobs says.

Data integration

In order to make these systems work, com-panies need to be able to integrate different software systems together, and this can be very difficult.

There are various security concerns if you are connecting together systems from different companies – although the level of concern depends on what data is being shared. For example, companies are usually more con-cerned about sharing production data than maintenance data, Mr Jacobs says.

The systems can often involve many different experts working together, both data scientists and domain experts.

Some companies put together big data inte-gration projects a decade ago, but then did not put anyone in charge of maintaining the data integrations – it was assumed that the various business units would do that. This can mean that the quality of the data integration grad-ually declines.

Sometimes people often end up “cobbling something together that works”, rather than developing a robust long term solution, Mr Zornio says.

Another challenge is that people sometimes expect their oil and gas technology to be as good and fast as the apps on their mobile phone, where it can seem that you can get an app to do whatever you want straightaway for a few pence.

However there are some examples of areas in the industry which have very good data in-tegrations. Mr Jacobs cites some companies in Australia, particularly in stream assisted gravity drainage heavy oil projects (SAGD).

In unconventional operations there is often more of a factory atmosphere which drives these sorts of integrated systems. “This evo-lution is a bit more practical - develop rapidly and sustainably,” he says.

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April - May 2017 - digital energy journal 5

Subsurface

GeoApplications, a UK company based in Brno, Czech Republic, has developed a new way to determine deviations in density of the subsurface – by studying shape of sea surface, based on set of precise Earth’s parameters in-cluding accurate geoid potential constant W0.

Their method, called Density mapping tech-nology (DMT), is a new geophysical method, which calculates completely new geophysic-al-physical geodetic data – Density Deviations. The data is processed together with many dif-ferent constants and ceofficients describing physical parameters of the Earth, to develop a density deviation picture which provides new information about density variations compared to gravity survey, the company says. Their ap-proach is not reprocessing of other geophysical data, but calculation of new geophysical param-eter.

The technology was invented 8 years ago by two Czech profes-sors - Viliam Vatrt, a specialist in geodesy, and associate profes-sor Lubomil Pospíšil, a specialist in gravity for petroleum explor-ation.

Since then, the inventors have been developing the technology and putting together demonstra-tions, based on public data, showing how it is able to identify potential hydrocarbon bearing structures. Two years ago, Brno venture capital company Opifer Ventures took an interest in the com-pany, invested in company and together they expanded the team of partners and advisors and incorporated experts from several fields of exploratory geology (Geophysics, Geoscience, Petrophysics, Complex geological interpreta-tion and Basin analysis). Now the company is making the technology more accessible for use in oil companies, for example by providing it as plugins to the popu-lar Schlumberger Petrel and ESRI ArcGIS soft-ware.

So far the technology has been verified for off-shore exploration and the company is sure it could also be used onshore.

Density deviations The technology grew out of a project Viliam Vatrt was engaged in, to develop a new way for unification of altitudes in the world, including altitudes for aeroplanes by GPS and other mil-itary use in NATO.

Mr Vatrt is a professor in the Department of Geodesy, Faculty of Civil Engineering, at Brno University of Technology, Czech Republic. Geodesy is defined as “the branch of geophysics that deals with shape and surface of the earth”. Mr Vatrt determined a “global geodetic con-stant” called W0, representing the gravitational potential of the Earth, irrespective of any tides or other factors, so it can be used in many appli-cations including DMT technology. This constant can be used together with the sea level at each point on the earth’s surface, which position can be measured by satellite.

Mr Vatrt noticed that the potential of earth varies by small amounts, based on a precise understanding of distribution of the masses in the earth’s crust. So putting all of this data together – the geo-detic constant, precise understanding of the true shape of the earth and other geodetic and geo-physical constants, variations in the sea level and changes to the satellite track, make it pos-sible to determine a picture of density deviation beneath area of points on earth. An enormous quantity of different coefficients are used in the calculation. It can show density at chosen resolutions de-pending on the density of point on earth’s shape. Application to petroleum Mr Vatrt thought that the method to determine density deviations might be useful in petroleum exploration, so he joined up with Lubomil Po-

spíšil, Associated Professor at the Brno Univer-sity of Technology, a specialist in geophysics, and an honorary member of the Czech Associ-ation of Geophysicists (CAAG). Lubomil Pospíšil is a gravity expert. He has worked in remote sensing for the Ministry of Geology in Moscow, and with the Winter Edu-cation Training Program of AAPG in Houston, working on reservoir characterisation (mapping surfaces, properties and volumes), subsur-face mapping, developing frontier exploration opportunities, and shapes of sedimentary bod-ies. Associate professor Pospíšil has been working to show ways that the technology could be used as part of an oil and gas exploration process. The density deviations are showing if there is a change in the density of the subsurface in the measured area. A change in density could be due to changes of geological structure.

Benefits The company has been developing geological case studies which can show how this technol-ogy could play a part in a broader subsurface interpretation process. The DMT Technology has extensive images available, showing how its density deviation maps have much higher resolution understanding than standard gravity deviation maps.

The company has used its data together with publicly available seismic subsurface data cov-ering the Rockall Basin (UK, off North West Scotland), around the Faroe Islands (north of UK), the Statfjord - Gullfaks area in the Viking Graben (West of Norway), the Southern North Sea offshore Netherlands, and the Beaufort Basin (Alaska). DMT technology would have identified in these areas different hydrocarbon bearing structures, such as subsurface channel complexes, small sub-basins and basement ridges. Existence of these structures have been verified by seismic data.

A new way to determine density deviationsA Czech company has developed a new way to determine density deviations – by new geodetic and geophysical approach which uses set of precise Earth’s parameters including accurate geoid potential constant W0

Prof. Viliam Vart

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Report from our production data conference in Aberdeen

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What does improving production mean? Most people in the oil and gas industry think they understand. But the answer is pretty complex because it is such a wide range of things, involving an understand-ing of the wells, the pipelines and the topsides, being able to spot and resolve problems quickly, and also looking for opportunities where it can be done better.

And all the time, it isn’t very clear what the results of the decisions are. You can see the current production with varying degrees of clarity (not all wells have flow-meters, and some of them are inaccurate and it takes a while to get the data). You can see when there are obvious problems, like slugging (big bubbles of something in the oil flow, which stops the flow from moving).

If something goes wrong, production en-gineers are under pressure to make fast decisions, because if they don’t, someone else (probably offshore) will make the de-cision for them, and they may not make it so well.

According to data seen by one of our speakers, up to 1 in 4 wells in the North Sea can have negative production, where opening the choke actually means the overall production is reduced – perhaps because this well connects to a lower pres-sure reservoir, it draws oil production from other wells down into it. That’s something good to know.

It also involves understanding the top-sides. The separators, removing water and gas, have a limited capacity. There is no point in maximising production from individual wells if the production flow is then constrained by the separators down-stream. And you also want to understand the causes of downtime with the topsides equipment, the most common of which is probably compressors ‘tripping’ (switch-ing themselves off due to high or low con-straints being violated or being manually switched off). This starts to get into the facilities management and maintenance domain, but it is all connected.

One interesting theme which emerged in the conference is that the big challenges can be split into platforms and tools. By ‘tools’ we mean the software tools which production engineers directly work with, to understand a flow, analyse something, look at different options and try to see what the results of a decision would be. By ‘platforms’ we mean everything these tools are built on – including the sensors and flowmeters, the data management and integration systems, the databases and the data exchange standards.

Both the tools and platforms should be handled in different ways. For the tools, you ideally want a competitive ecosystem of continually developing and refining different sorts of tools to help in different ways – understand a situation, analyse it, see the impact of decisions. These tools might be developed by engineers or do-main experts themselves, rather than soft-ware people.

For the platforms, you want it to be as solid as possible, changing slowly. The platforms take real IT expertise, and a fair bit of domain expertise as well, to design and build. But once built, they shouldn’t take much maintenance.

The costs of poorly managed production data are not obvious, but they could be-come more obvious in time. An audience member noted that one North Sea oil com-pany has an unofficial business model of acquiring assets and going through the data very carefully, to try to discover where the reservoirs are larger than the selling company thought, and it seems that was a successful tactic for them.

Low technical support

One interesting issue is the low amount of technical support which production engineers get. A survey of 35 oil com-panies by New Digital Business found that geological and geophysical staff typ-ically have one technical support person for every 17 professionals; drilling people have one for every 30 professionals, reser-

voir engineers 1 in 20, but production data people have one technical person for every 95 professionals. Production data could be called “last piece of subsurface data we haven’t grasped properly,” said Jonathan Jenkins, COO of NDB.

Companies also have IT departments, but IT people do not necessarily have the understanding of the production domain that they would need to provide assistance.

“This whole idea of support and having the right type of support is all part of the fundamental building blocks of getting production data more easily trusted,” Mr Jenkins said.

Steve Roberts

Steve Roberts, head of digital solutions with the Oil and Gas Technology Centre (and formerly head of field of the future with BP), attended the event and said he had found it a “really refreshing conver-sation.”

“A lot of themes resonate with me,” he said.

“I think time is right to make great steps forward. I had a privilege in BP of looking at global portfolio, here I’m looking at a regional portfolio. I think there’s a chance to do some things. You’re all struggling with the same sort of issues.”

How to improve productionDigital Energy Journal held a forum in Aberdeen on March 14 looking at what new approaches to digital technology can help improve production – which came up with some exciting ideas

Steve Roberts

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digital energy journal - April - May 2017 8

Report from our production data conference in Aberdeen

Intelligent Plant of Aberdeen has set up an ‘In-dustrial App Store where people distributing tools or ‘apps’ to help solve problems or im-prove productions can sell them.

So far, there are apps for monitoring plant and receiving notifications, connecting data to apps, managing controllers and analysing if they are over or under tuned, creating piping and in-strumentation diagrams with real-time data, monitoring trends, analysing alarms, monitor-ing subsea valve performance, understanding compressor performance and getting automated alerts about a potential wax build up.

Oil companies can use and test the apps on a pay as you go basis, running them on the cloud, and if they want to take out a subscription the costs are typically about $10,000 per app per year, paid for on a monthly or weekly basis. The benefits from a useful app, if it can help prevent a few compressor trips, can of course be in the millions of dollars.

Intelligent Plant takes 10 per cent of any sales, compared to a 30 per cent cut taken by Apple’s App Store. The app developer gets the rest.

Currently, “three or four” operators in Aberdeen are seriously looking at working with the apps, including Maersk Oil, which has done a trial with Intelligent Plant and is now planning to make it an integrated part of their operations.

“We want operators to stand up and say,”we are connected to this”, you can now offer us tech-nologies to use through this.” Said Steve Ait-ken, consultant director with Intelligent Plant.

One oil and gas customer said they see it as a ‘no brainer’, in particular because they have seen the same tool being developed multiple times, because there was previously no way to share the work, or even let other companies know that the tool exists.

The tools can be built by people from within one oil company, and then sold to other oil com-panies. They can also be built by any outside software company or individual. Apps can be built by people who have knowledge of that specific domain (for example experience work-ing with a certain compressor), data scientists,

software people, or perhaps all three.

He, believes that tools like these can make a big contribution to helping oil and gas companies improve production efficiency (the % of total time where the platform is operational). In the North Sea, this is about 70 per cent on average, but can be as low as 50 per cent. An increase in production efficiency means an in-crease in actual production.

There is plenty of data in oil companies which could be used to improve production efficiency. An analytics person who can gain access to the data, and pull out the right insights, can make a big difference.

Too often, the data is only available inside the software system of a company who built the system (such as the control system or historian).

Also monitoring software tools will usually need to store data as well as read data, so the oil company needs to provide access to a data store, which they don’t usually like (Intelligent Plant provide a separate, but integrated data store if this is the case).

You can login at appstore.intelligentplant.com with a Google account, or set up a new account, and then see the apps, download them, connect them with your data, and that’s it.

Advantage of the approach

The main advantage of the ‘app’ approach is that oil companies can test something out and see if it works before committing to pay for it (or paying upfront for software development costs for something they need).

The developers can try something out quickly (so they don’t spend too much money to see if something works). If it works, they get a stream of revenue enabling them to constantly maintain and improve the tools.

In the old days, a software person might have an idea, and show it to an oil major. The oil com-pany person says, “How much do you think this will save.” The software person says, I don’t know, I don’t have your data to work it out,

but it is clearly a lot of money. And I will need some money from you to develop it, and it will need to go on your network.

Then the oil company says, we’ll have to buy a server for it, which is quite expensive, and it will cost money to deploy it, but we don’t know what we’re going to save.

It is possible the oil company will find some funding and take the risk that it won’t work, but more likely that nothing will happen and the project doesn’t get started.

Another common route is that someone from the oil company has an idea and builds a tool in Microsoft Excel to show that it should work, then he wants to bring in an application de-veloper to turn it into software, connecting with the live database and sending automated e-mails if something is going wrong with the compres-sor.

But this route is not ideal either, because the oil company person is not a software person, and the person who built it does not have any ownership over it (usually the agreement is that intellectual property is owned by the oil com-pany). If it works, it won’t be made available to any other company. If it breaks then the ori-ginal software person will need to be available to fix it.

Integration to data

One of the biggest challenges of the approach is that it is very difficult to test out apps without access to the underlying data – and oil compan-ies can be reluctant to connect an app hosted on the cloud to their data stores.

But technically it is possible to connect an app to a data store in an hour and a half, if the oper-ational data is already available in an onshore network.

Intelligent Plant tries to help the app develop-ers by giving them tools to help them integrate. They can also maintain control of their soft-ware, but let people access it through the (In-dustrial) App Store.

Intelligent Plant – an ‘Industrial App Store’ for productionAberdeen company Intelligent Plant has built an ‘App Store’ offering modules to help improve production efficiency

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Report from our production data conference in AberdeenExamples

A commonly cited cause of the low production efficiency is compressors, which are prone to ‘tripping’ (switching themselves off due to a fault). Working out the cause of each trip can be very complicated.

Looking across the North Sea, analysis has shown that lack of maintenance is the cause of 15 per cent of lost production, but 55 per cent were due to operating practises, the problem was caused by something somebody did.

The alarm and event data analysis app was used to analyse 6 months of data for a compressor in the North Sea, and found there were 21 trips or shutdowns. For 6 of these, an operator pressed a button to shut it down. 15 were completely unplanned. The tool could be used to try to

determine which events were responsible for most of the shut downs.

Analysis of what else was happening when the trip happened should build up intelligence that can be passed onto an operator, telling them that a certain activity, done in a certain way, is likely to cause the compressor to switch off.

It is quite easy to calculate what savings could be made by avoiding compressor trips, by cal-culating how much production is lost due to the downtime.

There are also tools which can be used to try to understanding the relationship between the choke position and the production rate.

There are times when opening a choke valve on a well can actually lead to reduced production, for example if that well connects with a reser-

voir at low pressure, so if the choke is open it ‘sucks’ some of the higher pressure fluids from a neighbouring well back down. ““We’ve seen that on 1 in 4 (too high) wells,” Mr Aitken said.

The Wax Intelligence app can trawl your data historian (such as OSI Soft PI), and find what it thinks are the subsea temperatures, and tries to determine whether they are of producing fluids or injection chemicals. If it is producing fluids below the waxing temperature you can receive an alert that they are about to block.

You don’t need to show the app the tags on the data yourself, or build an asset model. The only configuration is to say where the server is, and where the app’s data can be stored. (This saves considerable configuration time which in itself can make a project unviable, or cause it to fail through inaction).

Oil and gas consult-ancy New Digital Business was re-cently involved in a project to help a UK Continental Shelf oil and gas company improve the way it manages its produc-tion data, so it would

be easier to analyse and gain insights from.

The work included improving the data which is generated from the oilfield, developing a single system which the data could be entered into which both hydrocarbon accounts and en-gineers could use, and actually loading up the data. From that point, it became much easier for engineers to build their own automated tools to look at the data.

Measuring oil production

The first step is to make sure there are good enough systems for actually measuring produc-tion at the oilfield.

Measuring oil production from a well is a lot more complex than measuring flow into a car petrol tank.

The meters can be very inaccurate, and some-times there are no meters on well heads at all. This means that flow readings need to be ‘back allocated’ – guessing how much has flowed from individual wells based on the reading from a downstream flowmeter, after flows have been comingled. This could mean a flowmeter at a processing facility or even a pipeline receiving terminal onshore.

Sometimes the oil flow includes water, and just 2-3 per cent of water in the oil flow can put pumps out of their specified operating param-eters, Mr Jenkins said.

Flowmeters are fairly easy to install, they can be clamped around pipelines. “These things should be everywhere,” Mr Jenkins said. ”For whatever reason they are not.”

Also, “they are often not calibrated. There’s no schedule or process for calibration.” Well tests could be completely useless if the flowmeters have not been calibrated beforehand.

Collecting production data typically takes about 30 days (based on an IDC survey of 40 oil com-panies around the world). The data is often e-mailed in spreadsheets.

Hydrocarbon accountants

Oil and gas companies typically employ hydro-carbon accountants, with a role of maintaining a master record of how much oil and gas have been produced. They typically receive the pro-duction data first. This data is then made avail-able to the engineers.

However there can be a cultural difference be-tween hydrocarbon accountants and engineers. Although they both working with production data, they typically rarely meet and work in a different part of the building.

The hydrocarbon accountants’ role is to work out how much production comes from each well. They are more likely to have a background in accounting, not engineering. They need to re-cord the volume of oil produced, allocate it to different wells.

Hydrocarbon accountants are typically work-ing on monthly basis, while most engineers are working on a daily basis (although not all of them). The accountants are also trying to pro-vide information as required in a contract, and show a company has fulfilled its expectations for production.

NDB – helping a UKCS company organise its production dataJonathan Jenkins, COO of oil and gas consultancy New Digital Business (NDB) presented a project where NDB has helped a UKCS oil and gas company improve its production data

Jonathan Jenkins

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Report from our production data conference in AberdeenSometimes, monthly production data is e-mailed to the hydrocarbon accountants, and daily data from the well historian is sent to the production engineers, which means there are two versions of the production in circulation in the company, and they might not reconcile.

Hydrocarbon accountants might struggle with the idea that a well can have negative produc-tion. Although an engineer will understand that it is possible that you might find that by opening a well, overall production actually decreases. This can be because the well connects to a lower pressure reservoir, and its pipeline mixes with the pipeline from other wells, and so ‘sucks’ flow out of the wells with a higher pressure.

Sandbox

A good data management system needs an en-tirely separate system for experimenting, where engineers can take samples of data and doing analysis on it with various software tools.

It is important to separate the master data from the sandbox data, so they don’t get mixed together. When you want to know the produc-tion from a certain well on a certain date, you don’t want to receive it in an old spreadsheet full of someone’s calculations you don’t under-stand, and broken links to other worksheet pages.

A solid data system

The oil company wanted a data platform which would provide a single version of the truth of production data, which people in all disciplines would be able to use. There would be a standard workflow for receiving data, checking it and en-tering it into the system. It would use standard data standards, not spreadsheets.

The oil company wanted to use the Energy Components hydrocarbon accounting software as the basis for this, because it had already acquired a license to use it. However it took “months of our time” configuring it so it would work for what both hydrocarbon accountants and engineers needed, Mr Jenkins said.

NDB’s work included talking to users and understanding what they were doing, mapping it out, then creating a master workflow showing how the data evolves from raw data to report-ing, and how the data store would need to be changed so the workflow could work.

NDB loaded up all the production data it could find into the system. Sometimes old produc-tion data is not available. For one major gas field, it could only access 3 years of data. The only available version of older data was within Schlumberger’s Eclipse reservoir simulation software, which is very hard to get out.

Hydrocarbon accountants hadn’t seen the need to keep copies of 3 year old production data, and engineers hadn’t asked them, he said.

NDB has built systems to automate the data loading process. The data historian, recording data offshore, can automatically tag the data to identify what it refers to, so it can be auto-matically loaded into the data store. This also eliminates errors.

Some manual work is required, including allo-cating a co-mingled flow to different wells, if they don’t have their own flowmeters. The data management processes “forced a whole bunch of new roles and responsibility onto people,” he said.

As a result, “engineers and hydrocarbon

accountants are friends, working on the same data, and working together,” he said.

“The discipline of common data stores, minimal but essential process, has helped an awful lot,” he said.

Dashboards and analytics

Once you have one version of the data, you can build dashboards from the live data, which the engineers all believe in – this oil company uses Schlumberger’s Avocet production operations software.

If engineers already know that they are work-ing on the right data, they don’t need to con-stantly test their results. They don’t need to be constantly searching for data from different well tests, historians and other sources.

You can start automating the processes which work on it. “Automated processes have been es-timated to save 50 days per engineer per year,” he said.

Some oil companies have asked how their data can be used to show how they can keep pro-duction fluids flowing better, linking together maintenance engineers, production engineers, subsurface people and facilities engineers.

Enabled by combining maintenance engineers and production engineers, subsurface people and all the facilities. “If that combined group people is working with data sources that they trust, it can make an enormous amount of dif-ference,” he said.

Staff are now designing new workflows, which can include collaboration. “That has made a fan-tastic difference to morale,” he said.

Joe Chesak spent five years working as a production analyst, essentially an IT technician, embedded in the production team of an oil and gas com-pany.

His experiences

in this role afforded him insights into how best to give his production engineers a digital advantage. And as a result he is off building some digital tools himself targeting production engineers, through a start-up company called Fablabs. As the only “embedded tech” person in that Norway business unit his experience differed from those of IT department staff or IT con-

sultants. The advantage of being an ‘embedded tech’ is that you live with the team, experience the rhythm of daily challenges, and gain a hands-on understanding of the business. Mr Chesak says, “Staffing this way goes a long way toward helping the company make the most of their data. It’s actually a cheap way to increase productivity.”

Aside from teaching production engineers a

Joe Chesak – experiences as a production analystJoe Chesak spent 5 years as a production analyst with an oil and gas company in Norway – essentially an IT technician embedded in a team of production and process engineers. This role afforded him insights into how best to give his production engineers a digital advantage

Joe Chesak

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Report from our production data conference in Aberdeenfew tricks--how to write their own data scripts and automate laborious tasks--he was able to use in-house tools to assemble a more holistic view of the entire production environment.

In the US, Mr Chesak worked in a number of data centric roles including at Microsoft, De-loitte, Fujitsu, and a number of start-up com-panies on the US West Coast. He thought his experiences working in these companies, where the digital technologies and their data were core business, could be cross-pollinated, put to good use in the Norwegian oil company. Production engineers “I wanted to get the right data to the production engineers, to give them full knowledge of what is going on when they make decisions,” he said. “That’s no piece of cake.” Production engineers are in a difficult position. They are called upon to assess a challenge and make a decision on how to proceed, within in a tight time frame, otherwise a decision will be made offshore. Offshore staff are trained to make a decision quickly. Usually that results in a safe, ‘default’ decision such as shutting in a well, waiting for the system to stabilize, and reassessing. Though safe, it’s generally non-optimal.

The difficulty can be to gather all relevant data and then vet the data before making decision from it. That requires cross checking values coming in from sensors, discussing with off-shore personnel what the data indicates, and meanwhile assembling a multi-disciplinary team to go over options. If the data is unclear or does not meet the team’s trust, then the deci-sion shifts to engineering judgement. Because at some point the team must make the call.

The engineers’ key barrier daily that there is always a cost for gathering the contextual in-formation needed to move forward. A produc-tion engineer’s best day is when every datapoint lines up pointing and a clear decision. “It’s easy for me to say, but data is the core business of the oil industry”, chesak said.

Experiences as “embedded IT” Mr Chesak was originally hired to help the oil company streamline its production report-ing, moving from an environment with plenty of spreadsheets to relying more on reporting tools such as Spotfire. However he eventu-ally identified a bigger problem that he wasn’t

solving, which was that the data itself too often untrusted.

Getting engineers to fully trust incoming data started with a total assessment of sensor data and its paths through data infrastructure. It of course involved time of the engineers them-selves. And it also involved the IT department who mainly handled outside vendors when building out data validation solutions. And as “embedded IT,” Mr Chesak moved into a con-nector role for the big IT projects, reducing the language barrier between IT and Production people. Mr Chesak has an MBA which he said had been a reliable guide throughout his career prior to working in the oil industry. But acclimating to oil industry culture was a singular challenge. Although he says that the MBA taught ow to persuade and influence people he ultimately got his best results by using his immediate team members as his front line of communication.

Building software While the work was going on, Mr Chesak also participated in a number of sales meetings with big software vendors. “They were very slick presentations, hitting all the buzz words, par-ticularly around Big Data. And like everything in the oil industry, the systems were big and ex-pensive,” he said.

“I often felt that perhaps a large complex soft-ware system was not the right answer. It should be possible to get better data to the engineers, in a process they could absolutely control them-selves to work out how to improve production. And ideally such a solution would have a small footprint.” But how would this ‘small footprint’ software be built and bought? It is quite hard for the com-pany to describe what they want and then find an external supplier to go off and build it. The communication around business needs is tricky. A reasonable way forward is to prototype the software in-house, built on-site with stake-holders always available to see it progress. Mr Chesak did a great deal of software prototyp-ing himself during his time at the oil company which he felt gave him an unfair advantage over the big players. Topside constraints Productivity could also be improved if it was easier to take the topside constraints into ac-

count in decision making. For example, the topside includes a separator to take water and CO2 out of the oilflow, and it has capacity lim-its on each flow. Topside processing is a shared resource of all wells. Even if the topside is spread across multiple platforms, it needs to be managed one system with all shared dependencies taken into consideration. “But historically and still mostly true today, production engineers place their focus on tun-ing individual wells or small groups of wells, rather than trying to align production to the lim-its of the topside”, he said. “It’s just too much to consider. I think there are plenty of software choices on the market for managing wells, but not much for optimising the whole system.” There can be a sense of competition among pro-duction engineers, when individual engineers want to maximise production from the wells they have been assigned to manage. The danger of course is local optimization at the expense of thwarting a maximum global production from topside. Alarms Productivity could also be improved with a bet-ter designed alerting systems. As an example, Mr Chesak once went offshore to a production control room, where several employees monitored a wall of screens, several alarm sequences were on. It was explained that the alarms were not concerning on their own, and that other contextual information made clear that they could be ignored.

He found it a big motivation when prototyping a system for onshore use. He said, “It seems to me that unless something is really going wrong, the most useful alert would be to tell someone that there is an opportunity to increase produc-tion here, or perhaps a need to simply choke back a well. But this requires that everyone trusts the data enough to not have to be shown the raw data. Then the computer can take over more of the logic, consider the context, and give a more granular alert or suggestion to the user.”

Engineering judgement and organizational learning

The term ‘engineering judgment’ is not in the Oxford dictionary. Usually it means that the team needs to make a decision with a deficit or

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Report from our production data conference in Aberdeensome distrust of the information the team has. And in such a case, intuition plays an important role, he said.

Intuition is a real and valuable resource particu-larly in the older generation of engineers. But when engineering judgement becomes a large part of the decision, then other data going into the decision is discounted, even for datapoints that are trusted, Mr Chesak said.

The shift to the ‘engineering judgement’ mind-set can lead engineers to feel that there is not much to learn from the data when some of it is tainted. It may have been more true in the past when an individual decision was considered more of a case study, somewhat isolated from other decisions and cast studies. But these days with Big Data analysis techniques within easy reach of any oil company, all data is useful, in-complete or not.

“You want to have engineers who measure everything they do and record it so it gets into a system where they can use it for a continuous learning process,” Mr Chesak said. “It’s not the sexy part of the work, but given the inevit-able digitization of the oil industry, it may be-come the best way to capture learnings from the past.”

EnergySys – the cloud is transformationalThe cloud means a big change in the way people acquire and work with software, says Peter Westwood, technical director of EnergySys

In the UK, “we’re seeing more and more production data running in the cloud now. It is genuinely more effi-cient, more product-ive, they have real

control over what they do with the business data. How they want to process it, manage it, calculate it, that’s all stuff we put in their hands.”

Many service providers say their product is on the cloud. But there is a difference between a “real cloud service”, as op-posed to software which is delivered via the cloud, he said.

A “real cloud service” should be some-thing which companies can use straight away, on any device, with nothing to in-stall. They should pay for it as a service, on a per-use basis, so you only pay for something you actually get a value from. You don’t pay for any hardware.

The Service can serve an unlimited num-ber of different customers. The service also directly serves people who use it, no intermediate IT staff are required.

Real cloud software will probably have been built specially to run on the cloud – if you take software developed to run on a desktop computer or server, make it available via the cloud, then it is not a real cloud service, he said. You can see this if you compare cloud native accounts software like Xero and software which has been put on the cloud, like Sage Online.

A similar argument applies if you are con-sidering moving your in-house data centre to the cloud. “A lot of people think, if I take my data centre - and make that work in someone else’s data centre, than I’m on the cloud. Sadly that doesn’t solve the problem. You still have a load of kit which you are still to some extent managing.”

One paradox is that some customers say they are ‘cloud first’ but use the term as a bit of an avoidance. “Almost always, that means ‘cloud tomorrow’,” he said.

Oil companies once saw IT as an asset, but recently have seen it as a cost centre, which they hate paying for. By going to cloud, it can become an asset once again. “IT becomes an enabling force that makes it safe for you to build systems that deliver reliable business growth,” he said. “It is not all bad news for IT folk. “

Scale and sharing

The logic behind cloud is clear – the cost per user of computer power is much lower if the computer is housed in a vast com-puter centre, rather than in a company’s own data centre.

It is similar to the gradual move of electri-city generation from a generator on each street in the early 1890s, to city or country size power stations.

But no-one owns their own power station, and similarly no user of cloud services needs to own their own cloud system, un-less they are a massive digital technology company like Google.

It fits with the cloud hosting business model that the cloud hosting company is not interested in providing personalised high level support – or will only do it for a large fee. “They expect you to under-stand how to get this going,” he said. This is indicated by looking at Amazon Web Services pricing models. Business support for a data centre will cost a few $100s a month, but if you want full support, where you basically delegate all understanding and control to Amazon, it shoots up to $15,000 a month.

EnergySys

EnergySys provides cloud software used by oil companies to manage production data. The software is also used to manage pipeline flow data, LNG plant data and crude oil pipelines.

Sixteen years ago, EnergySys was mainly building bespoke production data manage-ment software for clients, all of which had to be built individually, although each im-plementation had some similarities, Mr Westwood said. The software was installed on the oil com-panies’ systems, and EnergySys delivered software upgrades.

EnergySys has used cloud services for its internal systems for a long time, but seven years ago the company realised that it would be much easier and more efficient to deliver its own products on the cloud. It made the decision to move all of the soft-ware hosting to Amazon Web Services. The performance improved, because of Amazon’s investment “for example, they

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Aberdeen Subsea Expo reportcould afford much better disk arrays than we could!” Mr Westwood said.

EnergySys thought it could do IT well, and had years of experience running data centres, but it was nowhere near as effi-cient as the big cloud service providers.

Now EnergySys uses cloud systems for its entire business, including office work (via Office 365) and accounts (using Xero cloud software), Google for mail, Box for document management, basically every-thing, he said.

Mr Westwood said he felt enormous pleas-

ure when he received the bill for renewal of the service contract for the company’s in-house servers, some tens of thousands of dollars, and realised he could just throw it in the bin, because it would not need to run in-house servers ever again.

Cloud and security

People often raise security concerns with cloud. But then you have to compare the cloud with the security of what it would replace, Mr Westwood said. “The reality is, [many of the] existing firewalls are a joke, they don’t protect at all but [people are] comfortable with them.

“I was working with a client who had a ‘super secure firewall’. We set up a VPN connection to it. It could only use TLS 1.0 which is a terrible weak and unpleasant bit of technology from 10 years ago which has loads of known exploits. They’ve never upgraded the technology in their CISCO routers because they are too scared to change it.”

The stuff in the cloud is so much better [for security], better managed and de-signed, updated regularly.”

Getting ‘small pools’ into productionWhat is the best way to get ‘small pools’ – discovered offshore reservoirs, so far deemed uneconomic - into production? A conference session at this year’s Subsea Expo event in Aberdeen explored in depth

The Aberdeen Subsea Expo event in February held a full day discussion about how to get ‘small pools’ into production. Small pools were described as “discovered hydrocarbons with the wrong development cost”, or “unsanctioned discoveries”, or just “these damnable things.”

The topic of ‘small pools’ brings together every discipline the oil and gas industry has – subsur-face, drilling, field development and operations – since all are needed in order to drill and pro-duce a small reservoir viably. Although perhaps the subsea industry sees that it has to most to gain from putting them in development.

Most of the UK Continental Shelf ‘small pools’ discovered so far are in the Central North Sea, with a seabed which is well understood, and depths which can be dived to, we heard at the conference. So they should be relatively straightforward to put into production.

To understand small pools, consider that it is the way of the world that more resources can be found in small accumulations than big ones. Consider gold – gold nuggets have been found very rarely, sometimes people find small flecks, most of the gold mining is for very small gold particles, and there is a bigger volume of gold than all the gold ever discovered in the oceans, but in molecular size volumes.

So we can say that any given reservoir is far more likely to be small than big.

Many oil and gas projects start looking like

reasonable res-ervoirs, but end up as ‘small pools’ once more studies have been done on them, said Mike Tholen, upstream policy manager with

Oil and Gas UK.

“Wherever you look you find more of [these] things, there’s lots of them out there,” Mr Tholen said.

One oil company person once said, if it was viable to drill 5m barrel reservoirs, they could have a job forever.

So the business case comes down to whether companies can cut the costs of getting small pools into production – which may come largely to the speed they can be brought into production.

Analysis shows that any reservoir with under 10m barrels will be “hard work”. Although if costs can be reduced by 25 per cent, then 9m barrels become viable, he said.

These reservoirs typically have a very short half-life (time for production rate to be halved) of 3-4 years, he said.

All of the known reservoirs must have some-

thing difficult about them, otherwise they would have been developed by now.

Over the past 40 years, about 5.5bn boe of small pools have been developed, but there are 3.2bn boe not yet developed.

The economics need to look at the development costs and the operations costs.

One rule of thumb is that the ‘unit technical cost’ (the sum of the capital costs and operating costs divided by the number of barrels produced from a project) should be under a third of the prevailing oil price.

So with an oil price of $60, the unit technical cost has to be around $20. “Unless we get that right we’ll miss the opportunities,” he said.

The capital cost needs to be about $10 a bar-rel. So rather than expensive fixed platforms, it might include subsea and floating solutions. The decommissioning costs could be lower because some of the equipment can be moved around from one reservoir to another.

If the technical cost for the total of drilling, completions, and plugging / abandonment is under $25 a barrel, “that’s a business,” he said.

The economics for small pools often don’t show up the risk – if something goes wrong with the drilling, or the reservoir is not as expected, the whole project can fail. “Normal economics don’t apply to small pools,” he said. “They have

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Aberdeen Subsea Expo reportto be lower risk or higher value.”

And if wells can be built for under $10m that would be a great help, he said.

Carlo Procaccini, OGA

Carlo Procaccini, head of technology with the UK’s Oil and Gas Authority (OGA), presented OGA’s analysis, showing that there are about 350 dis-coveries adding up to 3.4bn boe which

are “technically re-coverable” and currently not being pursued.

Of these, 70 per cent are small (under 10m bar-rels), 150 of them are unlicensed. The other 200 are shared between 50 different operators.

Most of these discoveries are in ‘tie-back’ dis-tance, which means they are close enough to existing offshore platforms and pipelines to connect them together.

To put the 3.4bn boe figure in perspective, con-sider that total production in 2016 was 582 mil-lion boe. Total production to date in the North Sea is 43 bn boe, and there is a further 6.3bn boe of fields currently in production or under development.

So if it was possible to get all of the 3.4bn boe of small pools into production at the same time, North Sea production could rise by 54 per cent.

Meanwhile, there is a time urgency to get small pools into production because there is an in-crease in cessation of production of platforms (leading to decommissioning) and a decline in project activity, he said.

Of course, there is a reason why each of them has not been seen to be economic to produce to date, but it isn’t always the same reason. Some of them have heavy oil, and others are in tight reservoirs. There are “various degrees of tech-nical challenges,” he said.

OGA is trying to work out how clustering might work, for example one operator might be interested in specialising in high pressure, high temperature wells, and drilling a cluster of

HPHT small pools, if they were close together, he said.

Some are so close to existing platforms (with drilling rigs) that they could be accessed by drilling from the existing structure.

It is important for the industry to look at ways to reduce development and operating costs, including new drilling designs, or apply stan-dards. Mr Procaccini thinks there could be sav-ings of 15 to 28 per cent on some developments.

The 30th license round, coming up this year, will include 150 relinquished blocks (blocks which someone previously acquired, but are now made available because the operator did not build on them), he said.

Eric Marsden, OGA

Eric Marsden, area manager for the Southern North Sea and East Irish Sea (EIS) at the Oil and Gas Authority, shared some ideas to make small pools more viable.

Many of them have technical challenges – tight gas, poor rock quality, or off spec gas, which needs to be blended in order to access gas mar-kets.

But perhaps an oil company could specialise in small pools of a certain type, and in doing so learn how to better develop them. It could get economies of scale by developing several at the same time, processing the fluids through the same equipment.

OGA is using some of the data at its disposal to try to work out ways that the small pools could be viably developed. It can see the production profiles, and the capital, operational and de-commissioning costs. “We can aggregate in-formation and create insights,” he said.

“We’re trying to kick-start collaborative, co-or-dinated developments,” he said. “We are com-missioning our own studies - to understand potential of those areas. We have come up with a number of development concepts.”

Sometimes, “there are a number of discoveries in the same geographical area which are not moving,” he said. The operator says, “we’re struggling with gas price, can you extend the license 18 months,’ and it slips.”

Meanwhile the infrastructure is under-utilised and aging.

“This stuff doesn’t happen on its own,” he said. It’s a role we take very seriously - and working hand in hand with industry.”

If necessary, OGA can put pressure on com-panies to develop a small pool in one of their blocks, or give it to another operator.

Or if a small pool cannot be put in develop-ment because the owner of neighbouring infra-structure will not allow it to be connected, “we call the infrastructure owner,” he said.

“We don’t have that much time to get stuff moving. There’s every drive to move the ball forward.”

Graham Whitehead

Graham Whitehead, Satellite Developments Manager at EnQuest and participant in the ‘small pools’ panel of the UK’s Technology Leadership Board, said “there is a sense of ‘something good here but nobody knows what is about. It’s complex but not as complex as it appears.”

Last year, industry people said that there should be a better way to categorise small pools and put them in a list. It was hard to get information due to commercial confidentiality. But OGA took the task on and sorted out the data, of who owns what. (A report is online at http://bit.ly/OGAsmallpool)

OGA used the first half of 2016 to sort out the data and the second half analysing it, he said.

With this data, OGA can push companies to come up with plans for their licenses, and de-velop data about reasons that licenses aren’t being developed.

Another aspect is “engaging and innovating the supply chain,” he said. “You’ve got to know there’s a prize there.”

The Technology Leadership Board has identi-fied 5 key ‘pillars’ for getting small pools in production, as cluster identification, efficiency measures, adopting existing technologies, adapting and developing existing technologies and improving technology impact. “No one is

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Aberdeen Subsea Expo reportmore important than another,” he said.

Key technologies can be a more portable FPSO, subsea standardisation, hot tapping technolo-gies, and getting better access to infrastructure.

Gordon Drummond

One problem is that the challenge is not particularly big to any operator – so none of them have an incen-tive to really tackle it. “You don’t have anyone with enough ‘skin’ to make this stuff happen,” said

Gordon Drummond, ‎Project Director at National Subsea Research Initiative.

However it is in the national interest (and the government interest). “We need OGA to pull all this stuff together,” he said.

The challenges are not usually about closeness to infrastructure or the size of the field, it is other technical challenges.

One problem is fluid co-mingling, if the fluids from the small pool can’t be mixed with other fluids for some reason. Some fields have tight gas, heavy oil, high pressure / temperature.

Many of the small pools were last surveyed with seismic in the 1970s, and a new survey would show the subsurface in better definition.

Colette Cohen

Colette Cohen, CEO of the Oil and Gas Tech-nology Centre (and formerly SVP UK & NL with Centrica), said that behaviour change could be a bigger challenge than technology de-velopment. “We have brilliant technology, we have to change behaviour,” she said. “We’re so scared of [getting away from] what we already know and get comfortable with.

The efforts to develop ‘small pools’ look in some ways similar to the efforts to get uncon-ventional oil and gas working in the US – how-ever there is a big difference, in that the learning curve for unconventional could be much faster.

Colette Cohen said she was working in the US on unconventional oil and gas in 2008. “There was a much more rapid learning curve,” she said. It was an environment of being able to test something new every day.

However what unconventional in the US in 2008 have in common with small pools in Aberdeen now, is perhaps a level of despera-tion, she said.

At the time, the lower 48 US states were about to start importing gas, which they hadn’t done before.

Presentations from this event can be downloaded atwww.subseauk.com/7006/subsea-expo-2017

Gordon Drummond

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Aberdeen Subsea Expo report

Aberdeen Subsea Expo – a new management approachThe plenary session of the February 2017 Subsea Expo in Aberdeen explored what new management approaches would help the industry adapt to a new normWe can see 2016 as a year of making dif-ficult decisions, cutting costs and restruc-turing – but we can see 2017 as the year our industry actually changes, said Neil Gordon, chief executive of industry body Subsea UK in his opening address at the organisations’ annual conference in Aber-deen. “2017 is all about how we adjust,” he said.

“We do believe we’ve seen the worst, the recov-ery will be very slow. We’ve seen less deep water projects being sanc-tioned, a trend of moving to low

cost tiebacks.”

And lessons learned from developing small reservoirs at low cost could then be transferred to deep-water projects, he said.

Mark Richardson, Apache

“Before 2014, the industry was already in a crisis [which] very few have r e c o g n i s e d , ” said Mark Rich-ardson, projects group manager, Apache North Sea Ltd.

“At $100 [oil price], some operators weren’t making money. Production was going down and lifting cost rising. Pro-jects were delayed and overpriced, indus-try was heading to a car crash.”

“The oil price crash made people sit up and take notice. It may be a blessing in surprise”.

Perhaps the blame for the oil industry problems could be laid at the feet of Fred-

erick Winslow Taylor, author of a book in 1911 “Principles of Scientific Manage-ment”, who died in 1915.

The “scientific management” principles were that employees should be given de-tailed instruction and close supervision, and the work methods should be based on a scientific study, not “rule of thumb” work methods.

The oil and gas industry embraced these ideas, and continues to try to use them, al-though they are no longer applicable in to-day’s complicated business, he said. “This is what, I think, is the root cause of why were in [crisis] in 2014,” he said.

Today in the UK Continental Shelf, we see a reliance on policy and process, cen-tralised functional control, micro manage-ment, lack of trust; aversion to risk, a fear of failure, a “defer, delay and do nothing” culture and a focus on management rather than leadership.

The complete lack of trust could be the most important, particularly between the operator and tier 1 of the supply chain, he said.

There might still be too many people who are too well paid, which drives the aver-sion to risk and desire to stick within the boundaries. People realise that their jobs might be more secure if they don’t make decisions.

There is a big different between manage-ment and leadership, if leadership can be defined as “vision and getting the team to deliver.”

“Those faults have taken the industry to crisis point,” he said.

Meanwhile we are living in the “age of ac-celeration”, he said. 20th century manage-ment is no longer applicable.

Mr Richardson spent 12 years in the Brit-ish Army, rising to the rank of captain, and applies a military idea of “VACU” to a business situation, in terms of assessing

and understanding its volatility, uncer-tainty, complexity and ambiguity. This idea can be applied to oil and gas, he said.

The business environment is complex in that “an event anywhere in the world can instantly affect everything you do”. It is ambiguous, in that sometimes decisions need to be made without a full understand-ing of the facts.

Failure in itself should not be seen as a catastrophe, but “failure to learn from fail-ure definitely is.”

“We need to change our thinking,” he said. Otherwise, when the oil price goes back up, people will go back to where they were before.

A 21st century management style for the North Sea should probably have much more emphasis on leadership, and less “process, policy and procedure,” he said. “We need a sense of urgency, get faster at making decisions.”

“You can’t sit and ‘front end load’ and get all the facts [before making a decision]”.

Oil companies should also be relying more on the capability of the industry supply chain.

A good decision making structure means having a centralised intent (so the organi-sation as a whole is clear on what it is doing), but decentralised execution, with individual managers taking responsibility for their part of it.

Good managers have to be able to pass responsibility down to subordinates, he said. As an example, as projects group manager with Apache North Sea, Mr Richardson is ultimately accountable for everything that happens with projects, but he has project team leaders who are responsible for everything that happens within their sphere of influence.

Oil companies also need much more trust with suppliers, so they do not have to spend so much time doing ‘pre-qualifica-

Mark Richardson

Neil Gordon

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Aberdeen Subsea Expo reporttion’ he said. Oil companies should also make sure that they pay suppliers on time.

We need people who can take commercial and contractual risks, he said. “The biggest revenue is where the biggest risks are.”

There are many younger people who could be good managers. “We’ve got to give them the opportunity,” he said.

Perhaps the industry and the government together should also be rethinking whether we should do full decommissioning, Mr Richardson said.

The industry is currently obliged to follow OSPAR rules (The Convention for the Protection of the Marine Environment of the North-East Atlantic), which say that when oil and gas operations are concluded, the seabed should be returned to the condi-tion that it was in before the industry came along.

However, there is an environmental case emerging that it may be better to leave the platforms where they are, on the basis that the area around offshore installations has become a good breeding ground for fish, because fishing vessels don’t go near them. Fish supplies have been depleting everywhere else.

So perhaps, “leaving these things in place would make the greatest sense,” he said.

The UK’s role in OSPAR was linked to the European Union, and now the UK is planning to leave the EU, this can be re-thought, he said.

Apache benchmarks the cost of its projects against other operator’s costs, he said. It currently calculates that it is 50 per cent cheaper than other operators for subsea tiebacks.

To keep costs down, it does not employ onsite inspectors. It gives its suppliers a one page functional specification (of what the product should do, not how it should be built).

This way, it can run a $100m subsea tie-back project with just a four man team – a project lead, and three engineers with dif-ferent specialisms, he said.

It also gives its suppliers incentives so that

if the final cost is under budget they share in the rewards. “I went them to maximise their returns on my project,” he said.

And if the company is happy with work from one contractor, it ought to be possible to use the same company again, without going through an expensive tendering pro-cess, he said.

Phil Simons, Subsea7

Phil Simons, ‎VP Nor th Sea & Can-ada at subsea engineering, construct ion and services company Sub-sea 7, said that like many

other compan-ies, Subsea7 has

been through a “difficult and traumatic” period.

During the oil price crash the company has reduced its staff from 14,500 people to 8,000 people in 2 redundancy processes, and reduced its vessels from 40 to “just over 30”.

The company has been trying to find ways to retain its expertise but reduce its cap-acity, in order to reduce outgoing costs, he said.

The company now expects a “very quiet” 2017 and a “relatively quiet” 2018.

But from now on, the “real issue” is re-ducing the cost of subsea projects, which means a different way of thinking. “Now is time for radical change,” he said.

Up until now, engineers have been empha-sising minimising risk and not worrying so much about cost, he said.

But now they are being asked to come up with designs with cost as a higher factor. “Engineers are struggling with that con-cept,” he said.

Staff are not necessarily in the mood for developing new ways of doing things, after such difficult time. And many young people have taken voluntary redundancy

and lost faith in the industry. “We need to excite them and show them this is an industry they want to be part of,” he said.

“Everyone’s been scared about their job for 2 years. We’ve tying to install confi-dence, there is a job still there. Then they start to believe we want [them] to take more calculated risk.”

“We need to show, here is a new way of working. Everyone has a part to play in the future of this industry. Everyone needs to take part in this new radical change. If everyone believes in it, the outcome will be good.”

Companies need to move to more open and trustworthy relationships with clients, employees and suppliers. “Collaboration is one of the most misused words,” he said. One way to put it is, “Everyone needs to feel that they are wining,” he said.

“We’ve become very untrustworthy, with four people monitoring what one person does. A person from the client, the sup-plier, a 3rd party, my company, watching one person work.”

As a supplier, Subsea7 requests that its clients “give us a problem, let us come up with a solution,” he said. But “people don’t like to handover responsibility - they don’t like to empower someone else.”

Subsea7 promotes the “ESSA” mantra – eliminate, standardise, simplify, automate.

The company has asked workers to “tell us what the solution is”. Over the past two years it has had over 1000 suggestions from staff, which led to $40m savings in 2015 and $50m in 2016.

Subsea7 is trying to change its own control systems and reduce the number of docu-ments. “We give people more empower-ment,” he said.

David Lamont, Proserv

“I don’t think the past two years have been wasted, it has made us fitter and stronger,” said David Lamont, CEO of energy servi-ces company Proserv.

“It’s not products of technology that alone are going to be a solution, it is wrapping technology with people,” he said.

Phil Simons

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Aberdeen Subsea Expo reportProserv makes subsea con-trol systems (among other services), and has a number of projects up-grading subsea control sys-tems. “A year ago we had 10

projects, today we have 47,” he said.

Companies want to find ways to do more with their existing subsea assets, for ex-ample with tiebacks to other wells. But some subsea communication systems are as basic as Morse code, with signals for open and close, and not much else.

Mr Lamont said that one of the worst things people can say to him in a job

interview is “I know what you need”, be-cause “I don’t know what I need,” he said. “Every project, particularly marginal ones, is different.”

Also, suppliers, when visiting a customer like Proserv, should “leave their tool box on the ground” – because you don’t know if any of your existing tools are appropri-ate for the problem, he suggested.

Small suppliers

There were complaints from a number of small suppliers in the audience about how hard it is to sell their products to big oper-ators. One audience delegate said that his company had been through a range of ex-pensive auditing processes, but typically finds that the customer chooses the big company as a supplier. “We call it ‘no-one gets fired for choosing xyz’” he said.

Mr Simons from Subsea7 replied, “We’re looking at how we can use more smaller companies. We’re not perfect at it. We have a huge responsibility as a Tier 1 player to do this,” he said.

The problem of too many audits affects big companies as much as small ones, he said. “We’ve been audited 10 time on one project by a client and never a finding, and there’s no recognition they are wasting people’s time,” he said.

Mr Richardson said he thought the prob-lem comes down to “aversion to risk and fear of failure in big oil companies,” he said. “Middle managers have got too much to lose. You [only] get fired for fiddling expenses and importing risk.”

“It needs a different mind-set to drive for a faster cheaper way of doing business.”

David Lamont

BP and the Pipeline Open Data StandardBP is gradually its pipeline data to the Pipeline Open Data Standard (PODS). Eric Primeau explained how it works in a talk at the Subsea Expo in Aberdeen in February

BP is gradually moving its pipeline data to an open data standard model, called PODS (Pipeline Open Data Standard).

Eric Primeau, Geomatics Team Lead, North Sea Region, BP, talked about the work with a talk at the Subsea Expo event in Aberdeen in February 2017.

Mr Primeau runs BP’s North Sea Region survey department, with 8 staff and con-tract personnel. In this role he is respon-sible for site surveys, rig moves, support for construction and operations projects, management of geospatial data, devel-oping Geographic Information Systems (GIS) and developing BP charts, accord-ing to his LinkedIn page.

The advantage of putting pipeline data in the PODS standard is that it should be sim-pler and more efficient to manage, helping the company maintain control and owner-ship of the data, and improve access to the data. This should all reduce costs, he said.

There would also be benefits if the pipe-line changes ownership, or if you want to work with other companies and share data

with them, he said.

Having such a system can serve as a prov-able “integrity management process”, if anybody asks you if you have one. “PODS is the only a tool for integrity management. It is a database containing all information pertinent to the pipeline.”

For example, the system can be used to bring up all the video and still images of the pipeline you have taken to mon-itor integrity, and show how its condition changed over time.

But over the short term, migrating to PODS is tricky. There are naysayers around who say it will take a long time to do and create something which will just sit on the shelf, he said.

Making the migration should be a long term decision. It will lead to a complete change in the way the company manages pipeline spatial and integrity data, he said.

You will probably need new IT skill sets in the company, including with relational database management systems, and you’ll

have to work together with your company IT department.

BP has mature instances of PODS for Azerbaijan, Georgia and Turkey, and sys-tems at “various stages of maturity” for Trinidad, Angola, the North Sea and Mex-ico, he said.

Data upload

The big task with moving to PODS is up-loading all your data into it – which in-volves finding, accessing the preparing the data, he said.

It is a very labour intensive exercise. You might want to get a contractor to do it. There is a lot of detailed work and data mining involved, he said. You also need people with the skills to do the migration.

However the underlying idea behind PODS is that companies manage their own data, he said, so you don’t get this benefit if you ask a contractor to do it.

You have to decide if you just want con-

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Aberdeen Subsea Expo reportsulting, guidance and training from the contractors, you want them to do the data migration, or you want them to actually run and host the system permanently, he said.

BP worked with two different contractors, one in Vancouver looking after data for Azerbaijan, and one in Kansas City look-ing after data for the North Sea.

To get it moving, “you need lots of meet-ings with lots of people. If you forget to invite the right person it can fall over. You need by-in from the whole chain of people.”

There are some third party data loading systems, which can be “inconsistent and bug prone,” he said.

Staging and production servers cost £40k each. You also have to make strategy documents, implementation plan, instruc-tions for contractors.

Working with PODS

Companies commonly work with PODS data using the ESRI geographic informa-tion system software, running its ArcGIS software, which provides web browser ac-cess, he said.

The central database is relational not spa-tial, so every data point is described in re-lation to something else.

There can be between 5 and 600 data tables, covering issues such as location, geographic features, inline inspections,

physical inspections, pipeline facilities, regulatory compliance, risks, cathodic protection inspections, internal surveys, leak information, site facilities, compres-sion, damage prevention.

The standard PODS format “can be overly complex”, and there is a steep learning curve for people who are not engineers, or not GIS professionals, to use it.

Because of the way it understands data with relationships, you can only have one PODS “instance” installed on any servers. “This is the complex nature of having to deal with a relational database,” he said.

You can minimise the amount of effort by eliminating tables you don’t need.

The Efficiency Task Force

The UK oil and gas association Oil and Gas UK has put together an ‘Efficiency Task Force’ (ETF) of representatives of oil and gas com-panies, to try to work out how to reduce project development costs. It was put together in in Sep-tember 2015.

Some of the people involved presented their experiences so far in a session at the Aberdeen Subsea Expo event in February 2017.

The Efficiency Task Force is organised around 3 themes of ‘business process,’ ‘standardisa-tion’ and ‘Cooperation, culture and behaviours’.

Specific projects under each theme are inven-tory management, procurement, logistics, main-tenance, compression systems (under ‘business process’), subsea technology, valves and well P+A (under ‘standardisation’), and developing an industry behaviours charter and a communi-cations plan (under ‘Cooperation, culture and behaviours’).

Subsea standardisation

Steve Duthie, industry liaison director with Technip, is industry lead of ETF’s subsea stan-dardisation project.

The subsea standardisation group had 12 sub-groups, looking at ways to standardise detailed design, fabrication, flexibles, IVB (Inspection Verification Bodies), installation, pipelines and coatings, pre-commissioning, subsea production systems (SPS), surveys, trenching and backfill, umbilicals, and valves / flanges / fittings.

The project had three stages – to develop the approach, to develop the theory and apply the theory on actual subsea prospects, he said. Over 31 companies were involved.

It found that collaboration needs to be three way - operator to supplier, operator to operator and supplier to supplier, he said.

The first hypothesis was that it might be pos-sible to standardise around existing technology – but it became clear that this would be very complex, with some companies being reluctant to share their designs, and “problems with docu-mentation”, he said.

So instead, the project team looked at better ways of working from this point onwards. In hindsight, the project could be have been called “efficiency” rather than “standardisation”, he said.

One possible saving identified was by not fol-lowing all of the requirements of American Petroleum Institute Recommended Practise for installation of subsea umbilicals RP 171, he said.

“It has quite a lot of stringent requirements, maybe not [all] appropriate for UKCS,” he said. By removing these requirements there could be 15 per cent cost savings.

Other ways to achieve efficiency identified were to use free hanging risers, not solid caisson ris-ers, and looked at putting pipelines and umbil-icals (cables) in the same trench.

Overall savings identified were 25 per cent for each prospect, he said.

Two projects, thought to be ‘economically chal-lenging’ were chosen which the standardisation themes might be applied to – Centrica’s West Pegasus (a 3 gas well tie-back) and Chevron’s West Wick field development (a heavy oil tie-back).

All the big oil and gas companies are actively reviewing the complexity of their systems. “The question is, are they taking it far enough to get the benefits,” he said.

Industry association Oil and Gas UK put together an “Efficiency Task Force” to get the industry working together to improve cost and efficiency. Some of the people involved talked about their experiences so far in a session at the Aberdeen Subsea Expo

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Aberdeen ITF Technology Showcase reportPipelines and coatings

Alan Black, business unit director Subsea 7, led the pipelines and coating workgroup of the sub-sea standardisation project.

The workgroup looked developing ‘pre-quali-fied procedures’, so procedures would not have to be qualified every time. “It makes no sense that every operator should qualify the same coating. [With] every new project, we start again with long qualification process.”

Three other areas looked at were using alterna-tive line pipe, reducing supplier document re-quirements, and low cost designs. Subsea7 follows the mantra ESSA “eliminate, standardise, simplify, automate” to try to find ways to reduce work.

The company reviewed its standard documents requested from every supplier. “Last year, we asked suppliers what documents you think we

need, and we asked [our own] engineers. As a result, “we saw a significant reduction in the need for documents,” he said.

Typical costs of managing the Supplier Docu-ment Requirement List (SDRL) are £420k on a single EPIC (engineering procurement in-stallation commissioning) project. The review showed that 234 documents could be removed out of a total of 562 – leading to a cost saving of £133k, he said. This does not include the sav-ings to suppliers.

Some of the ideas from the subsea standardisa-tion project were applied to Apache’s “Callater” project, which Subsea7 worked on.

The project included a 3.9km pipeline bundle, with a 45 inch outer carrier pipe, a production and test pipeline, flow and return active hot water heating pipelines, and controls compon-ents. There is a six well slot manifold for Cal-later and a tie-in manifold tow head.

Apache engaged Subsea7 in the end of 2015, and installation will be completed in the first quarter of 2017.

The key factors are safety performance, fast pace and certainty of delivery, predictability of outturn costs and the appropriate management of risk, he said.

When workers were asked how they feel about working on the project, replies included “There’s a good feel about the project”, “Apa-che trust us to do what we say we’ll do”, “No man marking. Empowered to make our own decisions”, “Relying on our fit for purpose specifications and industry standards to meet the functional requirements, Supportive cooper-ation at every turn from a minimal (read suffi-cient) Apache project team.”

Presentations can be downloaded from http://www.subseauk.com/7006/subsea-expo-2017

ITF - using digitech to improve performance

ITF (Industry Technology Facilitator) held a conference session on digital technology as part of its Technology Showcase event in Aberdeen in March. The full title was “Ap-plied Digital Technologies to Improve Oper-ational Efficiency & Performance.”

In his opening address, Dave Lynch, vice president reservoir development with BP, stressed that BP sees digital technology in two groups – one is the mobility (includ-ing mobile computers, better tracking and tracing), and the other is around analytics, including cognitive computing and robotics.

To indicate the need for something to change, consider that BP currently has a reserves re-placement rate of 61 per cent (so it is only replacing 61 percent of what it produces). “We have to intervene, and digital can help us,” he said.

“We adopted digital as a key theme for the Technology Leadership Board,” he said. The aim is to figure out what the industry can col-lectively do.

Driven by disruption

Neil Logan, chief executive of digital consultancy In-cremental Group, said that change in digital technology has “fundamen-tally been driven by Moore’s law.”

“20 years ago the average $1000 PC was 1 million times less powerful than a $1000 pc today. In 20 years, the average $1000 pc computer could be equivalent to a human mind (in spotting patterns),” he said.

Disruption might not be the best way forward, but there has been a lot of it around, he said. It typically comes from an external force – like the digital camera companies were dis-rupted by improvements in cameras in mobile phones.

Today the oil and gas industry is desperately in need for transformation, and the Oil and

Gas Technology Centre should act as a cata-lyst for change.

Two interesting areas of focus are logistics and exploration. For logistics, the emphasis is on how digital technology could be used to better model the operation and propose changes to reduce cost. For exploration, the emphasis is on finding ways to apply the gi-gantic computer processing power to the most intellectually difficult problems in the indus-try, he said.

BP’s approach

Greg Hickey, project manager for digital operations with BP, talked about what the company is doing to transform its business.

“We find ourselves in a new operating en-vironment, tight margins and a lean organisa-tion,” he said. “We see the long term oil price being 50 to 60. We’re in a fundamentally different business. Digitisation of upstream is the lever we need to pull.”

ITF’s “Technology Showcase event in Aberdeen in March included a session about how digital technologies could be applied to improve operational efficiency and performance, with talks from BP, Total and Incremental Group

Neil Logan

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April - May 2017 - digital energy journal 21

Aberdeen ITF Technology Showcase reportThe approach needs to be more to digitise the whole business, rather than just technology adding value, he said.

If you look for technology which adds value, it leads to point solutions, such as to manage alarms or monitor equipment condition, per-haps a few points of efficiency increase in some areas.

But a digitised business is like today’s cars, which have integrated digital systems which lead to higher reliability, better fuel economy and early advice of potential failures. It can lead to 2 to 4 per cent improvements in over-all operating efficiency. “This is the journey we are on in BP,” he said.

As an example, BP is developing a ‘plant operations advisor’, which creates a desktop for every engineer, with information covering their main business challenges, and which is aligned with the way they work. “In 2 years we’ll give every engineer this capability,” he said.

They will have data and documents available at their fingertips, notification of relevant plant events in real time (including to their mobile devices), and notification of possible future events, identified using analytics. There will be tools to identify problems and work out how to fix them.

All of the software will run on the cloud. BP has agreed a strategic partnership with GE, which will host the data and software on its PREDIX cloud platform.

BP is doing the same thing in drilling and wells.

Altogether it should be possible to reduce un-planned downtime and improve the reliabil-ity of plants. People with the relevant skills will be available 24 hours a day, working in different places and time zones around the world.

It will make it easier to migrate to “new oper-ating modes”, including bringing in drones, robotics, and automated data gathering. There will be much more sensors on equipment and smart analytics.

The technology is only now becoming mature enough to use in this way, including with in-dustrial analytics and cloud computing plat-forms, and better data infrastructure, he said.

There are big challenges, including integrat-ing data and systems, aggregating the vari-ous ‘point solutions’, creating workflows and managing the organisations.

BP is finding predictive analytics “very ex-pensive to develop and maybe there’s not enough data scientists in the world,” he said. “The costs will be prohibitive and we will probably give up.”

Another challenge is working out how to automate configuration and deployment of the tools. Data gathering is still very manual.

It all leads to create the sort of business which “the next generation of staff will want to work in and current generation is very excited about,” he said.

Total’s offshore robot competition

Kris Kydd, Head of Prospective Lab Robot-ics R&D with French oil major Total, talked about Total’s work to develop better offshore robots, by running a competition.

Total wants robots which can go anywhere a human can go, on an offshore platform. The robots should be able to do smart reporting, such as for detecting leaks or making checks.

5 teams are competing in Total’s competition to build a better robot.

The third stage of the competition is taking place in March 2017.

The first stage in 2015 just covered ground level robot movements, in 2016 the robots had to climb stairs.

The goal is that the robots operate autono-mously – the operator just presses a button and the robot starts a test and produces a re-port.

The problem is far from solved yet – the ro-bots have to improve their ability to work autonomously, improve their reliability, and improve the visual and audio recognition.

The robots also need to find their way around obstacles, and provide information about the dimensions of the obstacle. In the next stage, there will be human obstacles. If the robot de-tects a human it should go into standby mode.

There are also experiments to see how the robot can manage without wi-fi communica-tions – if the communications switches off, the robot should find its way to a safe area. It will be useful to know the minimum data bandwidth a robot can operate in.

There will be a Eur 500,000 bonus for the winner of the competition, and afterwards Total will carry out a pilot project with the winner.

If the autonomous functionality can work reliably, the robots cold be set to work on unmanned installations. There may also be robots running on rails.

Wi-fi turned out to be a weak communica-tions protocol for robots, because there are ‘black spots’ with no coverage in quite a small area. So there will be a shift to the 4G LTE protocol.

Also perhaps Total was expecting too much from robots. “Robots do not like to multi task,” he said. “The shift is making robots simpler and more task specific.”

Making offshore logistics more efficient

Celerum, a spin-out company from Robert Gordon University, is developing software which can aim to make logistics to offshore platforms more efficient.

It is led by Professor John McCall, director of the smart data technologies centre at RGU.

Professor McCall believes that it ought to be possible to manage without 40 to 50 per cent of offshore vessels through better use and sharing of the deck space, and some algorith-mic analysis.

With the software developed by RGU, the software can recalculate and update the vessel loading plan, every time there is a new job.

Celerum has worked together with oil com-pany Nexen to improve its logistics. It has also worked with AAR Craib, a trucking company based in Aberdeen and the largest oil and gas haulier in the region.

The project was funded by Innovate UK, after Celerum won an Innovate UK competition.

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Aberdeen ITF Technology Showcase report

ITF’s Technology Showcase in Aberdeen

Oil and gas industry group Industry Technology Facilitator (ITF) held its annual “Technology Showcase” in Aberdeen on March 1.

ITF puts together joint technology research pro-jects, funded by a number of different compan-ies for their mutual benefit.

Introducing the conference, Dr Patrick O’Brien, CEO, ITF said that in this dif-ficult economic environment, it is great that there are still projects getting off the

ground at ITF. In-teresting current

projects include mechanical connectors for pipelines (to avoid welding), ways to anchor pipelines with lighter anchors. ITF is currently investing £4.5m a year in projects, he said.

There is a project to mixing ferromagnetic par-ticles in cement so the cement can be tracked easier through metal (for monitoring well ce-menting through production tubing) – this can be used to check well integrity at the beginning of the well’s life, and to help with well abandon-ment at the end. There are projects to evaluate fracture propagation in tight gas reservoirs.

Chevron recently installed its first thermoplastic pipeline (high strength synthetic fibre pipeline), which originated as an ITF project 7 years ago. It is also trialling a robotic snake arm, which could be used for inspection inside vessels.

McLaren

Dr Geoff McGrath, Chief Innovation Officer, McLaren Applied Technologies, KPMG Mc-Laren Alliance, talked about how his company is finding success helping transfer its technol-ogy development and implementation capability from McLaren to other industries, such as oil and gas.

McLaren Automotive is a UK manufacturer of sports and luxury cars, which has its own For-

mula One car racing team.

Dr McGrath’s background is as a mechanical engineer in the oil and gas industry, having pre-viously worked for PDVSA in Venezuela.

With McLaren Applied Tech-nologies, the company wants to transfer its or-ganisational ap-proach, not just its technology. This includes the way the racing team does rapid

prototyping of new component ideas, embraces new technology and is the first to try things out. In order to win For-mula One races, McLaren needs to be the first to do something, or push the limits of perceived performance for something.

McLaren’s culture emphasises data driven de-sign, leading to high performance production, and data driven decision making, leading to high performance operations, he said. Each racing car has thousands of components being innovated continuously.

The vehicle constantly communicates data about its operational state to the driver and a remote operations team.

All components are designed using a desktop software, then McLaren builds a sophisticated simulator of the car which can be used to digit-ally test new designs. If the results look good, then it can be machined (creating a physical ver-sion). About 90 per cent of components which pass the simulator test end up being used in a racing vehicle, he said.

McLaren also has a physical simulator which can be used to test components, where the driver sits in a seat on a chassis which moves, so it feels like they are in a real car, doing a constant speed lap of the circuit. Engineers think a one day simulator test is worth 1 week of race track testing.

The design priorities are to put the human (the

driver) first, to model the entire complex sys-tems and the overall environment, and to bring the designer into the operational environment.

This is important, because it is very hard for de-signers to get close hand experience of driving a car. “More people have been to space than have driven a F1 car,” he said.

In the Formula One race in Australia (March 2017), the racing strategy will be set by a team at McLaren’s office in Woking, UK, using a stream of live data.

Careful consideration is made of which sensors to add to the car – because it all adds to the weight. McLaren only wants to measure some-thing if it generates data which could lead to bet-ter decisions. “We don’t just measure because we can,” he said.

The data can be analysed to come up with sug-gestions for better ways the car could be built or driven.

During a 2 hour race, the computer systems are running thousands of simulations a second of ‘what ifs’, feeding live data into models and working out what to change.

For each driver there is a strategist and a chief engineer. The strategists are usually aged 25-27, which McLaren thinks is the peak for people’s mathematical ability.

They are supported by analytics / ‘artificial intelligence’ tools, which could be considered ‘cognitive enhancement,’ where man + machine can perform better than just a person.

There are 300 engineers for every driver alto-gether.

McLaren Applied Technologies is one of the fastest growing parts of McLaren in terms of profitability.

Car racing can be considered similar to drilling, with the driller is in a similar role to the racing car driver, the rig crew is like the racing car’s garage crew, and the office team is like the ra-cing car’s remote strategy team.

Oil and gas industry group ITF held its annual “Technology Showcase” in Aberdeen on March 1, with some interesting talks on where the industry is heading with digital and new materials – and what it can learn from McLaren racing cars

Patrick O’Brien

Dr Geoff McGrath

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Aberdeen ITF Technology Showcase reportMcLaren has teamed up with consultancy KPMG, which has skills in making pro-cesses work, and combines this competence with McLaren’s decision making support capability.

McLaren aims to work together with its regulators. “Racing is massively regulated,” he said. “We don’t treat regulator as an op-ponent. We don’t want to surprise a regula-tor. We often rely on simulation to try and show the value.”

Josh Valman, RPD International

Josh Valman, the 22 year old CEO of London company RPD (“Rapid Product Development”) Internat ional , ta lks about how his com-pany “rapidly develops” new

technology and tries stuff out, and how the oil and gas in-dustry might adopt the same culture.

RPD provides outsource product develop-ment for companies, mainly for digitally enabled devices.

Mr Valman’s background is that he was de-signing robots when he was 10 years old, due to a fascination with ‘Robot Wars’ com-petitions, and this led to making other things people wanted, like replacement dishwasher parts.

As a teenager in school, he set up a business working online, with payments into PayPal, and nobody asked how old he was.

He believes that innovation could be de-scribed as ‘the process of executing on new ideas – finding out what does and what doesn’t work’. so a true innovator could be seen as more of a fast tester than a thinker, and an innovative organisation is one with a culture for testing ideas.

As an example, consider that Google Glass managed to build a prototype in just one day, using another headset with the software run-ning on a desktop computer. Also consider that IBM, Apple and Ama-zon did not invest the PC, MP3 players or

e-commerce, but they were good at figuring out which aspects of them did and didn’t work, he said.

It is important to actually watch people to see if it is working, not just ask people ques-tions, because people don’t always tell the truth, he said.

Colette Cohen, OGTC

Colette Cohen, chief executive of the Oil and Gas Technology Centre (OGTC), said that OGTC aims to unlock more produc-tion from the North Sea, with the right invest-

ments in technol-ogy, and the right

atmosphere and culture of innovation.

“Behaviours are the most critical thing we need to change. It is kind of hard to get new technology deployed in our world,” she said.

“A lot of the way we do things - is of the 20th century not the 21st,” she said. “We need to create a new vision of who we are.”

Key areas OGTC will focus on are well construction, asset integrity, small pools, decommissioning and ‘digital’ which covers pretty much everything, she said.

In terms of ‘digital’, there is no shortage of data, but there people typically use most of it only when something goes wrong, not to predict something going wrong.

OGTC is aiming for a 50 per cent reduction in the cost of well construction and decom-missioning.

If the cost of decommissioning all North Sea wells can be reduced from £40bn (current es-timates) to £20bn, that frees up a large sum to be invested in new fields, including the 210 ‘small pools’ – reservoirs which have been discovered but deemed uneconomic.

And if Aberdeen develops expertise in vi-ably developing ‘small pools’ it can be ex-ported to other countries.

Asset integrity is largely about managing rust. If the oil and gas industry can develop solutions (such as plastic pipe) it could be used in other industries.

OGTC has a number of projects and field trials going on, and is looking for more small companies to work with, and has funding available, she said.

Geoff Nesbitt, Petrofac

Dr Geoff Nes-bit t , Group Head Technol-ogy Strategy, Petrofac gave a broader picture about what he thinks is hap-pening in oil and gas technol-ogy.

National oil companies have started cutting costs, perhaps for the first time, which has led to a huge cultural change. Engineering companies are selling hourly time for $25, which is “an absurdly low rate”. The role of international oil companies and national oil companies is changing dramatically, he said.

Interesting trends include data analytics, ro-botics and automation (including avoiding the need for people to go into dangerous situations), remote experts, autonomous in-spections, ‘smart subsea’, automated drill-ing, “digital twins” (making a digital version of a physical object),

Dr Nesbitt maps technology in terms of its cost (low to high) and the rate of change and therefore risk (low to high).

Data analytics have a high rate of change, and the cost can be both low and high. “Some analytics is very accessible and can be done very cheaply.

You can also throw a lot of money at it,” he said.

Integrated sensors can have a very low cost and low rate of change.

Operating equipment has a high cost and low rate of change. Getting a device into produc-tion can take 10-15 years, with a liability for any potential failure.

Josh Valman

Colette CohenGeoff Nesbitt

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Aberdeen ITF Technology Showcase reportDigital twins (a digital version of something in the real world) has a low cost and high rate of change.

Smart subsea systems have a medium rate of change and high cost.

The approach to technology varies with the rate of change and cost. If there is a high rate of change and low cost, you are looking at adapting technology developed elsewhere. If there is a high rate of change and high cost, oil companies should collaborate with other oil companies to develop it (perhaps in forums such as ITF).

If there is a low rate of change and low cost, the focus is on ‘excellence’ in how you do it. If there is a low rate of change and high cost, the focus is on investing and proving tech-nology, a ‘long march’ of getting tangible products into operation.

Gunther Newcombe, OGA

Gunther New-combe, director of operations, Oil and Gas Au-thority, said that OGA is “100 per cent behind technology. We want to see it adopted and de-ployed.”

As a geologist, Mr Newcombe has seen technology advance from coloured pencils 40 years ago to complex computer driven seismic surveying and processing now. But, “the pace of technology development is too slow, we need to reflect on that,” he said.

The industry should probably be moving faster to non-metallic pipelines. “We put metal in one of the most hostile environ-ments in the world - when you think about it - it is amazing,” he said. “Pipework is made of the same stuff as a decade ago.”

Also, if the ‘small pools’ which have been discovered but not developed were based offshore Japan or Germany, “they would be after it like a shot,” he said.

Some of the ‘new ideas’ being discussed at the moment have been in discussion for

decades. “We have to change the culture and behaviours,” he said. “We are a lazy indus-try, we have too much in the way of profit. We are very failure averse.”

Mr Newcombe emphasised that it may be worthwhile companies developing a con-structive relationship with the (UK safety regulator) Health and Safety Executive, if they feel that safety requirements are caus-ing unnecessary costs. For example, you can invite a HSE representative to your tests. “We’ve got to use piloting and test centres far more in the UK.”

“After 40 years in oil and gas, this is the most cohesive period I’ve seen, in terms of being joined up on technology,” he said. “If we keep doing this - we’ll achieve the change that we all want.”

Safety and command + control

Murray Cal-lander, CTO of software com-pany Eigen, said that safety rules often end up being inter-preted as a need for a ‘command and control’ culture, treat-

ing people at the lowest possible level, rather than encour-aging them to think on their feet and ques-tion why they are doing some-thing.

Gre ta Ly-decker, managing director, Chevron

Upstream Europe, replied that there are good and bad times to think about better ways to do something. “When you have a proced-ure to restart a furnace, and you’re about to start, that’s not a time to do it differently,” she said.

Colette Cohen, Chief Executive, Oil and Gas Technology Centre noted that even the army has managed to get beyond a culture of com-pliance – because the army knows that there

may be times when people need to think for themselves.

“To ensure people follow the procedure we have to embed a culture of command and control,” she said. “When you’re sitting in the recreation room thinking, we could have done it a lot different [that could be time to share the ideas]”

Greta Lydecker, managing director, Chev-ron Upstream Europe said she did not be-lieve that the industry only innovates in a low price environment, as some people have said. “I’ve seen us do fantastic things in an upmarket,” she said. “Chevron has been fo-cused on technology innovation all along.

“Maybe in tough times we focus on shorter cycle things and big projects at other times.

Remote working

Tony Edwards, CEO of StepChange global, pointed out that we don’t need so many driv-ers and operators, because so much can be done remotely.

“You still have drivers, you’ve [just] changed their work location,” Ms Cohen replied.

Standards

There was a discussion about data standards. Patrick O’Brien, CEO, ITF, pointed out that some people believe standards support in-novation, some people believe standards block it.

McLaren’s Geoff McGrath pointed out that once you have standards (for example for sensors and internet enabled devices), it gets much easier to build systems around them, rather than when you don’t know which sys-tem is going to win.

Lee Billingham, engineering manager - Energy at RPD International, said he had introduced the concept of “Technology Readiness Levels” to BP in a former em-ployment, describing it as a technology risk management process. But over time it turned into a barrier system, with people saying “it’s not TRL 5 so we can’t use it.”

Gunther Newcombe

Murray Callander

Greta Lydecker

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Aberdeen ITF Technology Showcase report

Jonathan Copp, technology man-ager, Chevron, upstream Europe, talked about how the company needs to find a pathway through various different goals, in a

conference session at the ITF Technology Showcase entitled “Emer-ging inspection and condition monitoring tech-nologies.”

The company’s overall objective is better asset integrity and reliability, as well as making sure people working in hazardous environments are safe. And a good production efficiency (the amount of time a platform is operating) “can make the difference between positive and nega-tive cash flow.”

The maintenance strategy can have a big impact on operating costs. And you have to choose between corrective maintenance (fixing things after they break) and predictive maintenance (trying to maintain things so they don’t break). The challenge is finding the right path between all of this.

There is often a need to inspect systems and structure which has not been inspected before, and get the data without any loss in production, and without any manned entry to pressure ves-sels for inspection.

Sometimes inspection can be made during scheduled plant shutdowns.

Condition monitoring tools can be built into newer assets, for example corrosion monitoring systems on subsea pipelines.

Overall you can have a ‘risk based’ inspection program rather than try to inspect everything.

“If you can see a problem sooner you can make a planned intervention that’s more efficient,” he said.

Condition monitoring has advanced a great deal. 10 years ago it was about sending data tapes to a condition monitoring vendor and then receiving a report. Now the company has in-house experts analysing data, located with other operations staff in an Integrated Operations Centre.

Maintenance can be scheduled months in ad-vance, and the company has better short term data models which help provide better under-standing.

Often equipment can be run outside the recom-mended service intervals, if you can see that no problems are emerging with it.

Making inspection simpler

Kieran Kavanagh, Director of innovation and data analytics with Wood Group, talked about ways that inspection can be simpler. “We are seeing more efficient, low cost, risk based, in-novative and reliable solutions,” he said.

It is useful to focus on understanding the leading indicators, which can show you that a failure is about to occur. This can be much simpler than

continuous condition monitoring and predictive analytics, he said.

For subsea inspections, you don’t need “work class” full size ROVs. Smaller ‘suitcase’ ROVs are being developed. There are subsea drones which can inspect pipelines, risers and other infrastructure.

For data analytics, the most useful is when you combine a human with the machine, rather than talk about human or machine. “We don’t’ see that changing soon.”

“Edge” analytics systems, where the analytics is done on the equipment itself and only tell-ing you when there is something useful to say, can be helpful. It uses less bandwidth. “If your tree can tell you something, let it tell you some-thing,” he said.

Virtual welding

Dr James Dydo, CTO/Principal Engineer, EnergynTech Inc presented an underwater welding robot, which is remotely controlled. Underwater welding is dangerous and banned in many places. So the company has developed a ‘virtual welding machine’. The idea is that a human trained welder operates the virtual ma-chine, which gives instructions to the robot.

There are many parameters which need to be right with welding, including the weld angle, electricity voltage and speed.

Maintenance – a mix of objectivesA maintenance program must help the plant achieve reliability – but without causing too much downtime, which has a big impact on operating costs. Perhaps technology can help work out the right pathway

Jonathan Copp

Where oil and gas is going with materials

BP sees material technology as so critical to its business that it has developed over $100m over 10 years in advanced materials research in a group of universities.

Sheetal Handa, Associate Director, BP-ICAM “International Centre for Advanced Materials”, said that “materials impact every operation we [at BP] do. Corrosion, pipe-

work, fouling, new metal alloys, low wear surfaces, high pressure system, long life bear-ings,” he said.

He was speaking at a conference session at the ITF Technology Showcase in Aberdeen on March 1, “Transformational Manufactur-ing & New Materials to Reduce Costs.”

BP’s research is done at the University of Cambridge, Imperial College (London), the University of Illinois (USA) and the Univer-sity of Manchester, which takes a hub role.

Modelling is a main theme – including atom-istic modelling, molecular modelling, fluid dynamics, process modelling, he said.

The oil and gas industry is making big strides with understanding materials at a molecular level, additive manufacturing (3D printing) and advanced forming, we heard at a special session at the ITF conference in Aberdeen

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Aberdeen ITF Technology Showcase reportAlso imaging and characterisation is a major theme. “We have some really fantastic capabilities,” he said. “We can see hydrogen sitting on a metallic surface.”

The research aims to achieve better under-standing of why materials behave like they do. “It is about understanding why corrosion happens in one part of a pipeline and not in another,” he said.

Steel is prone to hydrogen embrittlement, so it would be good to develop a steel which is resistant to it, perhaps through a better under-standing of the micro structure.

It is also looking at separation processes, in-cluding the way it can reduce the salt level in water BP uses for enhanced oil recovery. “We want to understand why current mem-branes work the way they do,” he said.

It is also looking downstream, where BP has a lubricants business. Pressures in an internal combustion engine can be 140,000 PSI. “You ask molecules to lubricate that and survive. We know it works but don’t understand how it works,” he said.

Research showed that the material commonly used in lubes, molybdenum disulphide, is structured in layers, and one layer can slip over another layer. Once you understand this, “you can say, which other molecule can deliver this.”

Another focus is bringing scientists from dif-ferent disciplines together. “The big process is where you have interfaces on those disciplines.”

Additive manufacturing

C er t i f i c a t i on o r g a n i s a t i o n Lloyd’s Register is trying to de-velop a certifica-tion or assurance system for com-ponents which have been 3D printed, said Andrew Imrie,

Global Product Launch Manager, Lloyds Register.The people involved in 3D printing prefer the term ‘additive manufacturing’, because

the components are made by adding, rather than subtracting (as they are in for example milling), he said.

It can be hard sourcing spare parts for many pieces of old equipment – so a big benefit if you can just scan a component and print a copy of it. With this method, you can also make a component from one part which was previously made from 15. This can mean that there are less pathways for the component to fail, he said.

One problem with the world of additive manufacturing is that a lot of the develop-ment work is proprietary, so data is not avail-able which would help certify a component as safe, he said.

Also, not everything is consistent. The pow-der which is used can vary in particle size. There are times when powders with differ-ent particle sizes have been mixed together, perhaps by a company who was not aware that the powder might ultimately be used in a safety critical application. “We have to understand what we are certifying,” he said.

There is an ISO standard for additive manu-facturing which is “quite generic”. But if a narrower standard was developed (for ex-ample, just for oil and gas components), it could be restrictive and get in the way of in-novation.

Lloyd’s Register has developed some guid-ance notes for people thinking of using addi-tive manufacturing, together with technical specialist company TWI. They are available online at lr.org/en/services/additive-manufac-turing

Advanced Forming Research Centre

Stephen Fitz-patrick, senior manufacturing engineer with the machining and additive manufacturing team at the Ad-vanced Forming Research Centre (AFRC), talked

about some of the additive manufacturing projects the Centre has been involved with.

Rolls Royce wanted to make stator vanes, a component of a jet engine, with additive manufacturing. A solution was developed by the University of Sheffield, including a way to eliminate manufacturing defects and in-spect the powder before manufacturing. The components have been incorporated in flying engines, with “tens of thousands of equip-ment run hours”. AFRC is now trying to find ways to reduce lead time, cost and waste, he said.

Another example was building crushable structures for a space capsule coming back from Mars, which (by crushing) would ab-sorb the shock of landing, strong enough to stand the impact, and heat proof. The Manu-facturing Technology Centre put together a lattice structure material.

A third case study was to use additive manu-facturing to repair landing gear and turbine blades on an aeroplane, which could reduce the costs of repair.

A fourth case study was developing an addi-tive manufacturing laser metal deposition procedure for oil and gas components which are difficult to weld. Some typical oil and gas alloys. Corrosion resistant steels and HRSA (Heat resistant super alloys) are difficult to weld. New metal forming processes are being developed, which can enable up to 80 per cent better metal utilisation, he said.

Magma Global

We already have pipelines made by additive manufacturing carbon fibre pipe in the North Sea, developed by a company called Magma Global.

Charles Tavner, commercial direc-

tor, of Magma Global explained that the pipe uses less material to make than standard pipe, which makes it lighter and easier to handle. Also the supply chain is much simpler. It has been used to carry hydrocarbons. The pipe is spoolable and can take high pressures. It costs much less to build than steel.

Andrew Imrie

Stephen Fitzpatrick

Charles Tavner

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Purchasing

How Select Energy uses standard eInvoicingSelect Energy Services, a water-related service company to the oil and gas industry based in Gainesville, Texas, switched to an electronic invoicing standard system in 2012 when they joined OFS Portal. Randy Friedsam, director of credit and collections, explained how it worked.

Standardized electronic invoicing, or eInvoi-cing, can enable oil and gas operators, and their suppliers, to reduce the costs of the purchasing process. Though implementation costs can be signifi-cant, an investment in eInvoicing should deliver significant long-term benefits. It also contrib-utes towards each company’s move towards digitalization in oil and gas. Select Energy Services switched to electronic invoicing when they became a member of OFS Portal in 2012. OFS Portal is a member-based group of up-stream oil and gas suppliers leading the global adoption of eCommerce in the oilfield. Select provides services to more than 400 oper-ator customers across the lower 48 states. Select had acquired 18 companies within a span of 3 years, from around 2012 to 2015. None of the acquired companies, nor Select, had a stan-dard way of eInvoicing. Also, prior to becoming an OFS Portal mem-ber, it did not have a secure way to send data to customers. Randy Friedsam, director of credit and col-lections for Select Energy Services, joined the company in 2011. He had previously led process improvement as it related to credit and collections at BJ Services Company where he worked with member repre-sentatives of OFS Portal. Through his experience with OFS Portal, he knew standardized eInvoicing would allow Se-lect Energy to simplify its invoicing processes, gain efficiencies and reduce expenses and er-rors. So at Mr. Friedsam’s behest, Select joined OFS Portal. Benefits of OFS Portal For Select, after data protection, one of the

main selling points of an OFS Portal member-ship is freedom from fees imposed by networks hired by operators.

To put that in perspective, if a service company has revenues of $500M a year, transaction fees can amount to hundreds of thousands of dol-lars annually.

N o w , a p -

proximately 89 percent of Select Energy’s rev-enue is under contract in a catalogue system, eliminating both transaction costs and price matching errors associated with those custom-ers which translates to significant cost savings year to year. Also, Select saw an OFS Portal Membership as an opportunity to have more presence in the community and participate in its work groups, thereby influencing how the organization, and eCommerce in oil and gas, progresses. In addition to Select, members of OFS Portal include Baker Hughes, GE Oil & Gas, Hallibur-ton, Schlumberger and Weatherford. Mr. Friedsam pointed out that as a member, Se-lect can request the operators it does business with to use the OFS Portal agreement. This works especially in cases where an oper-ator may want Select to use direct entry to a portal rather than B2B integration, or use a be-spoke data template for catalogs rather than the agreed single standard. Since they are all members they can use the same format across all customers, which pro-motes efficiencies for all members and oper-ators alike. “The non-manual process features one template across an unlimited number of catalogs and operators. The process is simple and structured, and the exchange of data is secure, which is of

utmost importance,” Mr. Friedsam said. “In addition, when customers ask for price validations, eCommerce provides this, along with spend analytics.” Select was particularly impressed with OFS Portal’s price validation process, which is critical for reducing errors, he said. “When you enter the information on the tem-plate, there is a validation that will tell you if there is an error such as unit of measure or duplicated items. “I have absolutely seen that errors have been caught and we can go back and fix those errors within our ERP,” he said. “It’s another check and balance for Select.” By streamlining the invoicing process, Select has also profited from quicker payments and fewer price disputes. About OFS Portal OFS Portal implements a common methodol-ogy for eInvoicing which includes use of open and royalty free eCommerce standards, such as Petroleum Industry Data Exchange (PIDX). OFS Portal’s model is technology agnostic and works with every Enterprise Resource Planning (ERP) System, such as SAP and Select’s choice, Microsoft Navision, as it relates to the Accounts Receivable/Credit Collection eInvoice process. It enables members to send data and trans-actions securely and confidentially through business to business (B2B) integration and publish contractual data through its Catalogue Management System. The benefits also go to the OFS Portal mem-ber’s customers. The OFS Portal Operator Community has reported cost reductions in ac-counts payable resources. For example, a large independent oil and gas company was able to eliminate the role of 35 full-time employees performing data entry and reassign them to other roles.

Randy Friedsam

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Operations

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