Turning real-time data into information

Tony Edwards of StepChange Global discusses how the digital oilfield can have a direct impact on production success, and we look at how to equip operators with the tools they need.

By Oil & Gas Engineering August 2, 2016

Getting real-time data from the oil field or pipeline to the people who need to act on that data has always been a challenge in the industry. Today, new technologies and new strategies are making it easier to collect and analyze data, but the oil and gas industry has been slow to adopt these systems. In the first of a two-part series, Oil & Gas Engineering spoke with Tony Edwards, CEO of StepChange Global, a U.K.-based digital oilfield advisory and consultancy company focused on designing and delivering integrated operations services, about how the oil and gas industry is taking full advantage of a new way of working, and the effect it has on reducing costs increasing efficiency. Here are edited transcripts of that conversation:

OGE: What are integrated operations?

Edwards: There is no single definition of integrated operations, digital oilfields, or whatever name you care to choose. Generally, the term "integrated operations" means: "Keeping real-time data and information from your operational environment, equipment in the field—where there are wells, pumps, and pipelines—and using that data in a remote location to optimize the performance of your assets."

But it’s not just about the technology; it’s not just about the data of bits and bytes, it’s about what you do with the data. And it’s about how you change your work processes, how you align your organization, and how you get your people on board to make the most of that data and information.

What we see is that early on, when this concept first started evolving, which happened around the 2002-2003 timeframe, there was an assumption that if we provided smart people with data and information, that "If we build it, they will come."

Of course. that didn’t happen. They carried on doing things the old way. They had access to some data and information, but most of the time they simply weren’t using it. It was therefore recognized early on that you had to do more than just provide the data and information to somebody’s screen or to a room to get the performance gain that we were looking for.

The other elements are about how you update and change your process workflows and the workforce at the workplace, and how you use the data and information you have in a more timely fashion. How do you get your people on board with actually changing the way they’ve been working for the past 15 or 20 years when they haven’t had that data and information? How do you align your organizational team structures whether at the team, asset, regional, or corporate level—to make the use of that data and information to really add value in an operational asset?

OGE: This can be categorized into three parts: technology, the people side, and the organizational side. And these three components are working together. A lot of companies or organizations might have the technology together, but the data is going into a box and it’s really not improving things. The data isn’t translating to information. How do you get people to actually use the information effectively?

Edwards: At StepChange Global, we paint a vision of what it would be like to work this way. We have done this in many companies in all regions around the world.

It boils down to three things: doing things faster, the ability to work remotely, and a move toward a multidisciplinary approach that supports change integration. First, do things faster, so that you have real-time data and information. You’re moving from a world that was meeting-based: "Oh, I have a problem today, I’ll call a meeting tomorrow, then we’ll go away and work on it, and we’ll come up with the answer next week," to a real-time, proactive way of working, with the data and information at your fingertips to be able to solve that problem, now. That’s number one-moving to more real-time data and information while you’re working. Second, it’s about being able to do work remotely.

When I worked offshore 15 years ago in the North Sea, the platform I ran was a physical island, a data island, and an organizational island. If you weren’t on that platform, you had very little opportunity to impact the performance. At best, we had email and the telephone. We had to be self-sustaining and self-supporting. We could get limited support from the beach, and if we had an opportunity, we could fly somebody out. But all that takes time, is costly, and has the potential for a health and safety breakdown. Now, the ability to do work remotely means that you can divorce some work from its location. For example, why do we need planners at an operational site? That sort of thing that can be done remotely. Spending time in front of a computer screen at an operational site can be done remotely. Taking certain tasks off the platform and back into an operations center reduces cost, risk and allows immediate access to support.

Third is a move toward a multidisciplinary approach that supports change integration. At the end of the day, what are we trying to do? We are trying to optimize a molecule of oil and gas from the reservoir or an oil well all the way to an export meter, pipeline, or whatever. In the case of LNG, it’s a ship. Now that’s inherently multidiscipline. We need reservoir surveillance engineers, petroleum engineers, production engineers, operations guys, facilities people, pipeline, and maybe if you’re working in a gas environment, contracts.

In the past, during dead time in that meeting-based world, the fact that these people were in five different teams and scattered throughout the building—or in different buildings or even countries—was not a problem. But now we have real-time data, information, and the ability to collaborate by co-locating. By having multidiscipline production optimization teams, we have the ability to react on a timescale that is proactive enough to affect change. And we can do it fast. The boundaries in the organizational model of some deeply function-based companies prevent them from keeping up with data and information. They’re just not fast enough.

The thing that is most often wrong is the level of trust between the guys who work in the field—swinging hammers and turning valves—and those who are viewing the data and information and trying to make an opportunity available. If those two teams don’t trust each other, nothing happens. This means that the digital oilfield and integrated operations becomes not a technology project, not a process workflow change project (although both of those are key), it becomes a transformation program where you’re actually changing the way people work; you’re changing the relationships between people in the field and people in the office.

Learn more about Edwards’s thoughts on key technology enablers and preventive maintenance.

OGE: What are the key technology enablers that get this information to where it needs to be?

Edwards: First you have to ask some questions about the data you are collecting. Do you measure enough information in your plant? Do you have enough sensors in your plant to measure the condition of your assets, whether they are wells, pumps, or vessels? And so on. You know about the move towards automation. You know about integrated control and safety systems in automation, where a significant amount of instrumentation at the plant is a key enabler.

But beyond that, how you get that information out of the automation system and store it in a way that makes it available to your enterprise system? We don’t want everybody playing with the control system; that’s just not a good way to go. What you want is to extract that data, put it on the server, and make it available to your engineers so they can play to their heart’s content, analyze the data, and look for opportunities for performance improvement.

The other key enabler is bandwidth. There is a lot of discussion about when digital oilfield and integrated operations really start. We’ve been doing things such as remote control of small gas platforms and pipelines for a very long time. You can trace the beginning of the evolution toward a digital oilfield back to when high bandwidth communications became available. And one of the reasons this started in the North Sea—and in particular, the Norwegian sector of the North Sea—is that there were a couple of telecom companies that were laying fiber optics across the North Sea between Norway and the U.K.

At that time, they couldn’t make it go all the way across the North Sea without a repeater station. There were two companies, BP and ConocoPhillips, that were offered bandwidth in exchange for housing repeater stations on their platforms. So back in 2002-2003, a couple of operations in BP, ConocoPhillips, and Statoil suddenly had 10 Mbps of bandwidth offered to them for free. At that time, it was an amazing amount of bandwidth. And some very smart people started asking questions about what they can do with all that bandwidth.

OGE: How do you determine what you set up automatically versus the other things you could do instead?

Edwards: There are a couple of things to consider. We recently did an engagement with an operation in Calgary. Each morning, a petroleum engineer retrieved data from a hard drive, stored it in spreadsheets, and spent the next three hours opening every spreadsheet for 24 wells to verify proper operation. Next, the engineer reviewed the results to determine which actions to take to improve well performance to offset a potential decline.

Now, that entire spreadsheet is completely automated. He gets a comprehensive overview of his 24 wells, and he gets a notification sent to him when one of them is going out of limits. In addition to enabling him to look after the 24 wells in the current operation, it potentially allows him to look after the 240 wells that are coming online with the new operation. Not only does it allow him to do things more expediently, now he’s doing it only when it’s required. If it’s required three times a day, he does it three times a day. If it’s required once a week, he does it once it a week.

In this case, optimization is not just once every 24 hours using data that’s 24 hours old, based on yesterday’s data and trying to predict what needs to be done for the next 24 hours. Wells are monitored continuously based on a management by exception approach. It’s these incremental changes that identify the opportunity to optimize in real time, which would not be possible doing it from a spreadsheet.

The other issue is scalability—especially in what we see going on in shale oil in Eagle Ford. The number of wells involved—whether they’re wells being drilled or wells being operated—is so huge. How do you get a petroleum engineer to manage hundreds, if not thousands, of wells instead of tens of wells?

OGE: On the operational and maintenance side, does having all that data make preventive maintenance scheduling and decisions easier?

Edwards: That’s correct. Of all the analytic areas, machinery analytics is by far the most advanced. This can be brought in from numerous regional equipment manufactures as support services. However, what you’re really doing there is buying yourself time. Instead of having a situation where you have from hours to a few days advanced notice to a problem with a piece of equipment—with a machine, pump, compressor, or turbine—you’re now actually getting weeks, and sometimes many weeks. This allows you to move from corrective to preventive, and from reactive to planned. That puts a lot more stability in your ability to plan and implement your maintenance program.

OGE: You mentioned getting people on board. What are some of the other challenges you see here, and how do you recommend that they be addressed?

Edwards: When considering at business cases, we look at three types: quantitative, qualitative, and enabling. The quantitative business case involves knowing how much extra oil and gas I will get out of the ground for spending this sort of money. That’s the metric everybody relies on. But a qualitative business case asks, "What’s in it for me?"

We must articulate a vision of how we will make their lives better on a day-to-day basis. This is not about command and control. This is not about directing from the operations center what gets done in the field. It’s about engineers in the office making themselves useful in supporting the guys in the field to do the real work. As long as you pitch it that way-that we’re going to give them the remote support that they’ve always deserved but never had-then you can overcome a lot of the resistance to change and gain acceptance. This is not about telling people what to do. This is about helping you with your day-to-day work and making life easier for you. And it’s important to paint that vision.

OGE: It can be tough to get around personal preferences of guys wanting to be out in the field. Is this perhaps a cultural issue we must overcome?

Edwards: It is exactly that. How do we incentivize our people’s behaviors to encourage them to do the things we want them to do? Around 10 years ago, we did a workshop about digital oilfield and integrated operations for a North American gas asset. We explained that there are three teams: operations, maintenance, and a well intervention team. These typically are stand-alone, isolated teams, and they do their work.

What we’re doing with digital oilfield and integrated operations is providing transparency of performance regarding how we do our maintenance, how we run our wells, and how we run our production and operations in such a way that that performance becomes visible and any anomalies in the way we incentivize people become apparent.

And then we must do something about it—change the incentivization model. This is why it is not good enough to give you the data and information presented, you have to look at the other dimensions of what we would call an operational capability. You have to look at the technology, the data and information, and getting that data and information to the right place at the right time. You have to look at the way processes are run. Are you just running well tests once a month because you’ve always done it once a month, or are you doing it continuously by exception?

Then you have to convince the people to make that change in the way they are working, and build those trusting relationships between the people in the field and the people at the control site. What should be the organizational models, team alignments, team structures, and the way we incentivize our people to ensure this actually works? There’s a large amount of effort done on the technology and around the process workflow, and less done on the organizational people change, and yet, that’s the key to success.

ONLINE extra

See additional stories about the digital oilfield linked below.

Check out the October 2016 issue of Oil & Gas Engineering for additional thoughts from Edwards on the digital oilfield.

Original content can be found at Control Engineering.