Remote operations centers earning keep through drilling optimization, 24/7 support, ‘remanning’

Posted on 08 September 2010

By Linda Hsieh, managing editor

Shell has real-time operations centers in six major hubs around the world that are primarily used for multidisciplinary well planning, optimization engineering and 24/7 real-time monitoring of global assets.

Shell has real-time operations centers in six major hubs around the world that are primarily used for multidisciplinary well planning, optimization engineering and 24/7 real-time monitoring of global assets.

As with most implementations of new technology, the technology itself is rarely the biggest hurdle. It’s the people – we humans with our fears, our hard-to-break habits, our apprehensions, our sometimes irrational behaviors – that’s the tough part.

When real-time operations centers, or RTOCs, emerged in the early part of the 2000s, it seemed quite a simple concept. Using information-sharing technologies, software, the Internet, etc, to build collaborative hubs that could pool expertise and resources to improve a multitude of E&P operations spread out over any range of geographical locations.

However, as many soon realized, making an RTOC a true success, getting it adopted by employees and making it a valuable part of a company’s drilling & completion operations around the world – that takes more work than you might think.

“People built these collaboration centers, put people in them, and they thought everything would be great. But you have to teach and facilitate collaboration. It doesn’t just happen. Developing new work processes has to be guided continually and driven by management,” said Katherine Cannon, Baker Hughes BEACON global centre operations manager.

Shell is increasingly taking a “horses for courses” approach to real-time operations centers. In the Gulf of Mexico, this means RTOCs focus on the prevention of NPT – trouble associated with well control, lost circulation and borehole stability.

Shell is increasingly taking a “horses for courses” approach to real-time operations centers. In the Gulf of Mexico, this means RTOCs focus on the prevention of NPT – trouble associated with well control, lost circulation and borehole stability.

The company has a network of 25 collaboration centers worldwide that use the BEACON (Baker Expert Advisory Centers and Operations Network) platform to deliver “digital oilfield” services.

Shell also uses RTOCs, located in six major hubs around the world, for multidisciplinary well planning, optimization engineering and real-time monitoring of its global assets. Eric van Oort, wells performance improvement manager for Shell Upstream Americas, has been involved with the company’s experience with RTOCs since the beginning. Although these remote operations centers now contribute significant value to the company’s well operations, it wasn’t always this way, Mr van Oort recalls.

“It’s very easy to put an RTOC in place. Most of the technology is readily available on the market. In a sense, you can just buy an RTOC anywhere. But making it work for you is quite a different thing. It requires very significant changes in work flow,” he said.

For example, Shell has implemented well-defined communication and decision-making protocols that make it clear who the decision-makers are in different scenarios. “Once a red flag occurs, we start communicating with our decision-makers, whoever they are. They may be on the other side of the globe,” Mr van Oort explained.

For on-site rig crews, this kind of shift in work flow and responsibilities is a big change, and one that most will not welcome initially. It essentially brings in a group of outside decision-makers to what was once a local operation to watch over rig crews’ shoulders, looking for mistakes.

“We’ve worked on that for years. I won’t tell you that at the beginning it was easy because we suffered from this big brother syndrome as well,” Mr van Oort said. “But once an RTOC starts to add significant value, like helping to prevent stuck pipe incidents, the rig will see that. And once they understand you’re on their side, you’re there to keep them out of trouble, then the battle is over. The technology kind of sells itself.”

That initial push will require not only the support of senior management but those in the organization with operational credibility. “It’s not a trivial issue, and I think this is what most companies underestimate and where they make mistakes,” he said.

In addition to its six RTOC hubs (Houston; New Orleans, La.; Miri, Malaysia; Muscat, Oman; Port Harcourt, Nigeria; and Aberdeen, UK), Shell has a number of satellite centers as well. These smaller facilities are increasingly being used in what Mr van Oort calls fit-for-purpose applications, where RTOC-type technologies are used differently for different assets.

“We’re using kind of a horses-for-courses approach. For instance, for Upstream Americas, we are putting together smaller-scale collaboration rooms that we can use for more remote directional drilling of some wells in our onshore prospects in the Americas,” he said. Two centers have already been built, one for its Magnolia prospects in the Haynesville and another for Groundbirch in Canada. Other centers are also being considered as Shell expands its onshore portfolio in North America.

In the Gulf of Mexico, a fit-for-purpose use of RTOCs means there’s a focus on the prevention of nonproductive time – trouble associated with well control, lost circulation, borehole stability. Yet in Oman, the biggest driver is efficiency and invisible lost time.

“Maybe your best rig is making connections slip to slip in three minutes, but you have other rigs in the fleet that take six or nine minutes. So not all the rigs are as efficient as they could be,” Mr van Oort said. “The RTOC would characterize that and help to put a correction plan in place to get every rig to the same standard as the best rig.”

Shell’s remote centers also tackle drilling efficiency optimization by administering tools that are actually visible to the driller at the rig site. These might be special calculators that measure vibration severity or mechanical specific energy – information that the driller can use to drill faster or extend bit runs, etc. In the Magnolia prospect, these types of tools have helped Shell to go from 100-plus days per well in 2008 to fewer than 35 days per well now.

“Those are some spectacular improvements… So clearly the RTOC earns its keep through NPT reduction and efficiency optimization, where the return on investment is far more than 10 to 1 in terms of the money invested and the value we can get back in cost savings.”


Baker Hughes uses a suite of information communication technologies and software to connect its BEACON centers to rig sites around the world. These centers not only provide technical support and drilling optimization services, but they also make “remanning” possible. The company has been able to move many employees who previously had to travel to the rig site to centralized office locations.

Baker Hughes uses a suite of information communication technologies and software to connect its BEACON centers to rig sites around the world. These centers not only provide technical support and drilling optimization services, but they also make “remanning” possible. The company has been able to move many employees who previously had to travel to the rig site to centralized office locations.

Baker Hughes has developed a number of its WellLink technologies in recent years as part of its BEACON platform for the digital oilfield. They deal with remote access of real-time rig data, drilling data and wireline data, production and pump monitoring and static file management. These technologies have enabled the company’s collaboration centers around the world primarily to monitor and optimize operations without having to go to the rig site.

More recent applications of these collaboration centers have been with video technology and remanning, which means moving parts of the work that were traditionally performed at the rig site to remote, centralized “office” centers, according to Ms Cannon, who is part of Baker Hughes’ BEACON Enterprise Services group and oversees the company’s global network of RTOCs.

She believes that video technology has brought a significant payoff to the company’s investment in building BEACON centers and building a video-ready network. Aside from video collaboration rooms, which have been in use for years, the company has introduced a small handheld wireless web cam called Onsight to provide technical support for repair & maintenance (R&M) workshops and rig support. It’s being used to help with tool makeup, testing troubleshooting and maintenance from remote locations by specialists.

For example, if a downhole pump fails, the service company and operator would usually perform a tear-down of the pump together to find the cause of that failure. Traditionally, that would involve representatives of both companies traveling to one location to do the tear-down. “We do a lot of that just by video now, and it has been a massive HSE savings for both us and our clients,” Ms Cannon said.

A major success also took place recently with the webcam in Africa, where downhole tools were being tested prior to delivery to the rig. “We couldn’t get a successful test and couldn’t figure out why. We were just at the point of saying, OK, we can’t send the tools, when we decided to use the camera quickly to connect to the support team in the UK,” Ms Cannon recalled.

Within 10 minutes, the support team diagnosed the problem: There was a tiny blown fuse in the tool makeup, which the support team was able to spot via video. The fuse was replaced, and the tools went out as scheduled. “Without that camera, the tools probably would’ve been shipped back to Europe,” she said.

Baker Hughes is currently working to roll out this video technology to offshore rig sites as well, although network bandwidths have to be tested to determine if they can handle the size of high-definition videos. To do that, the company is running a pilot project offshore Canada using the cellular network.

“We realized what a big part R&M played in reducing NPT. You often miss out on the R&M side of things, but using the Onsight cameras to involve tech support for all the tools going to the rig, that reliability is absolutely key to performance,” Ms Cannon said.

Another application of remote collaboration centers has been in remanning, where Baker Hughes has reduced the number of personnel needed offshore by 50% or more, she said. Monitoring of real-time information 24/7 to optimize overall performance and paperwork (logging, petrophysical analyses) are now all done by people in the office using information communications technology to connect to the rig site. Larger-scale remanning also can be done with services such as reservoir navigation, drilling optimization, pump management, liner hanger downhole technical support, etc.

In Norway, where remanning is done at higher levels than in many other regions, close to 60% of Baker Hughes’ staff who would’ve been offshore can be remanned during operational peaks – this means they’re either in an office onshore, or their responsibilities have been changed. Baker Hughes’ cross-training of personnel facilitates this flexibility, allowing for efficient and HSE-compliant remanning.

To achieve remanning, a multitude of tasks has to be mapped out, defining roles to identify duplication and to best determine which could be shared, which could be moved to an office and which aren’t needed anymore for a specific project.

“It maybe something simple we’re doing five different times, like entering into the database a well name or hole ID. That can be done by different groups on the rig at any one time,” Ms Cannon said, and those efforts can now be streamlined into one task for improved efficiency.

A more complicated remanning would be, for example, with the surface logging system, generally made up of two people catching formation samples and two people monitoring/managing data in the cabin. In some instances, Baker Hughes has worked with the drilling contractor to catch samples instead. The two remaining Baker Hughes data operators might be cross-trained with MWD so they can make up MWD tools and handle MWD monitoring.

Part of Ms Cannon’s job is to make sure the necessary cross-training, for disciplines such as drilling, completions and fluids, is defined. Associated training courses and competency matrices must be redefined as well.

Remanning has also allowed the company to use the same head count for more jobs, driving personnel efficiency to operations. Ms Cannon recalled a job where an operator in the Middle East asked Baker Hughes to run a new technology. There was no expert available in that country at the time, but instead of turning the job down, a call went to collaboration centers in Europe, where engineers were available to run the service remotely from the UK. “We’re able to do more jobs for the same head count,” she said.

In 2006, the company kicked off 24/7 operational technical support centers in Norway. Since then, the service has been expanded across Europe, Russia and the Caspian region and is now being launched for Asia Pacific and the Middle East. “In traditional organizations, we rely on our social network for support and technical support. It’s only as good as the buddy that you know to call,” Ms Cannon said. The 24/7 tech support centers formalize that network so everyone knows there is someone somewhere they can call for help any time of day.

“Especially for the remanning operations, it has made a huge difference knowing you can get support 24/7. Once you get to those upper levels of remanning and really changing the way we do services, it’s critical that everyone knows how to get a hold of people who know they have a responsibility to work with you and resolve your problems,” she added.


Although optimization, R&M, monitoring and planning are key applications of remote operations centers and will continue to be, the future of these facilities is looking more to drilling automation, said Aaron Swanson, director of managed innovation for Baker Hughes.

This automation will take remote operations a step further to closed-loop machine control of the downhole process as well.

“Service companies are starting to understand that, as we move to automation, the way our services will be delivered is going to fundamentally change,” Mr Swanson said. The number of systems at the well site that acquire and collect data must be reduced, and being able to share that data among multiple users will be critical.

The challenges in this closed-loop automation are certainly many (see rig automation article on Page 24), but Mr Swanson believes that the technologies to get there already exist, and change is coming.

For service companies, instead of having a directional driller steer the well from inside a remote collaboration center, there will be a machine steering the well from inside a remote collaboration center. Perhaps only one directional driller will be needed to monitor multiple machines doing directional drilling for multiple wells.

Taking that knowledge and expertise of directional drillers and putting them into a digital format used by computers is a key step, but Mr Swanson said that the drilling industry only has to look to other industries to see that the technology exists to do this. “Look at the manufacturing and automotive industries with controls. Look at the mining industry with robotics and mechanization. The military industry with drones. The medical industry with remote surgery,” he said.

Using computers, a directional well could be drilled using not just the experience of one directional driller but the cumulative expertise of thousands of directional drillers, Mr Swanson said. A human directional driller will see a finite number of wells in his career from which to build his knowledge base; there’s no such limit for a computer.

He emphasizes that automation is not about job loss. “It’s about job transformation. You’re shifting one job into a different job,” he said, pointing to the introduction of robotic arms into the automotive industry as an example. It made people afraid that their jobs would be taken away. It didn’t.

“Before that arm was there, there was nobody on the floor to maintain arms. There’s someone there to do that now. There was no one looking at how the arm worked and monitoring its status, but there is now. It was job change, not job loss,” Mr Swanson said.

In the drilling industry today, there are jobs being done – not because they add value to the well – but because that’s the way the service is provided. With automation, duplicative tasks can be removed, and new jobs will be created based on the newly integrated system. “The work will change from what you do because you have to, to what you do to contribute value,” he said.

BEACON and WellLink are registered trademarks of Baker Hughes. Onsight is a registered trademark of Librestream.

Remote technical support improves jackup operations

By Linda Hsieh, managing editor

Using remote technical support from NOV has helped to resolve issues with cathead malfunctions, TDS-encoder problems and drawworks brake dragging problems on Jindal Drilling’s Virtue 1 jackup.

Using remote technical support from NOV has helped to resolve issues with cathead malfunctions, TDS-encoder problems and drawworks brake dragging problems on Jindal Drilling’s Virtue 1 jackup.

When it comes to rig equipment on offshore rigs, real-time monitoring and intervention from remote onshore operations centers performed by the manufacturer’s technicians – subject matter experts – can add significant value to drilling contractors and help to minimize nonproductive time related to equipment failures.

For the past two years, Jindal Drilling has been using the eHawk system from National Oilwell Varco (NOV) on two of its highly automated jackups – Virtue 1 and Discovery 1 – with great results, said drilling manager Aniruddha Pattnaik. Because these two rigs had numerous critical pieces of equipment onboard controlled by SBCs, Jindal Drilling decided there was significant potential value to using remote diagnostics, he said.

After initial teething problems with Internet connectivity and bandwidth issues that required fine-tuning, eHawk started realizing that potential. On Virtue 1, for example, real-time monitoring and intervention has helped “extensively” to solve problems with cathead malfunctions, TDS encoder-related problems and drawworks brake dragging problems, he said.

The eHawk system is backed by NOV’s support centers in Houston and Norway. The primary tool is a datalogger computer system installed on the rig and connected to its control network. That control network has access to all the SBCs operating the tools. Support centers can then monitor the SBCs in real time during operations (for real-time diagnostics) or trend archived data.

“Each of the rigs is equipped with a datalogger that serves as an archiving terminal and a gateway to the rig’s control network,” Mr Pattnaik said. Software is then used to log each data point from the rig tools.

“The data that is archived remains on the rig and is not transferred to the support center. It is used to help in troubleshooting issues that come up with the controllers,” he continued. The datalogger and support center are linked via a secure VPN connection, allowing NOV technicians to view the data, move software to and from the rig, archive software and modify it if needed. The link is up 24/7, but the connection to the datalogger computer is on demand.

One of the most significant advantages of using the system has been 24/7 access to experts, Mr Pattnaik said. “Subject matter experts (SMEs) will be contacted whenever an issue requires their expertise to solve it.

The NOV support center has one hour to make this decision. Once the decision to contact an SME is made, then the SME is required to work the issue within four hours, he explained. Efforts to contact SMEs vary depending on the criticality of the issue. If the rig is down, that’s a high-priority issue that will get access to an expert at any time of the day, 365 days of the year. Less critical issues may be postponed to business hours.

Troubleshooting efforts with the support center also help rig crews improve their knowledge of the equipment involved. Trend curves can be generated for system performance and troubleshooting analysis, Mr Pattnaik said.

1 Comments For This Post




Leave a Reply



Recent Drilling News

  • 20 April 2015

    ExxonMobil exec calls for urgent action on US LNG exports

    The US may be at risk of losing economic opportunity and the ability to solidify its role as a global leader in energy production – unless the government moves to approve liquefied natural gas (LNG) exports...

  • 20 April 2015

    Kongsberg simulators selected to enhance training in Mexico

    FIDENA, on behalf of Mexico’s SCT has selected Kongsberg Maritime offshore simulators for the Marine Education Center in Ciudad del Carmen, Campeche...

  • 15 April 2015

    DNV introduces steel forgings RP to increase subsea standardization

    Steel forgings are important building blocks for subsea components and are often tailored to meet end-users’ specific requirements. This results in long delivery times...

  • 14 April 2015

    BSEE issues proposed BOP, well control regulations for public comment

    On 13 April, US Secretary of the Interior Sally Jewell announced proposed regulations that call for more stringent design requirements and operational procedures for critical well...

  • 14 April 2015

    Wood Mackenzie: Deeper cuts may be needed to achieve cash flow neutrality

    The rapid and aggressive response by oil and gas companies to low oil prices has stabilized the sector; the price required for companies to be cash flow neutral in 2015...

  • Read more news