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Xage Enforcement Point extends network security to individual devices, protecting millions of previously exposed IIoT machines and legacy control systems.

Today Xage Security announces Xage Enforcement Point to deliver universal access control for industrial operations. Xage Enforcement Point (XEP), for the first time, enables role-based access control and single sign-on for every device, from legacy control systems to the newest IoT machines––even those previously lacking any access control protection.

XEP works with Xage’s tamperproof security fabric as a unified solution for industrial operations. Xage’s security fabric is deployed at on-site gateways that can protect multiple legacy and IIoT devices at once, providing access control, password rotation, and managed interactions at the any-to-any level for maximum oversight and protection. Meanwhile, the fabric’s tamperproof replication capabilities enable centralized management and monitoring combined with XEP’s decentralized in-field enforcement.

“As industries evolve, operators are left with legacy systems and IoT devices interacting with disparate levels of security. Today’s reliance on network-level protection, where a breach on one device can comprise a significant portion of operations, is insufficient,” said Pete MacKay, Chief Product Security Officer at GE Renewable Energy. “Universal access control for devices, controllers and applications is fundamental for safe, reliable operations and the ability to securely adopt Industrial IoT at scale.”

XEP extends role-based access control to individual devices according to pre-established tamperproof policies secured in the nodes of the Xage fabric. Edge-to-cloud monitoring gives administrators visibility into and control of all access attempts, whether successful or not. Any attempts to unplug or bypass the XEP generate management alerts in the fabric. XEP ensures that individual industrial devices if ever compromised, are isolated individually – not in a group of other critical, uncompromised assets.

“Companies lose millions of dollars in direct costs from a single IoT breach. The decline in reputation and customer trust, including stock valuation and earnings, is even greater; and it’s only going to get worse,” said Duncan Greatwood, CEO of Xage. “Today’s patchwork of vendor-specific security products, unprotected systems, and attempts at network-level isolation are insufficient at best. With the Xage Enforcement Point, we’re now providing comprehensive cybersecurity for every device while avoiding changes in system software and maintaining the value of customers’ existing hardware investments.”

Beyond cybersecurity, XEP improves efficiency by enabling any-to-any machine-to-machine cooperation and automation, securing production data from source machine through to the cloud, and matching technician access rights with qualifications and job functions to reduce on-site human errors. XEP works across all systems and equipment, current or legacy, and is applicable to virtually all devices, such as machines, controllers, meters, and sensors regardless of the vendor, generation, type, make, model, or connectivity. XEP enables remote access and control at oil pads, wind farms, mines, factories and other distributed or harsh environments, thus limiting on-site visits, saving significant amounts of time and money, as well as reducing risks to employee safety.

 

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Oceaneering has been awarded a two-year Integrity Management contract with Total E&P Danmark to support its significant Tyra Redevelopment project in the Danish North Sea.

Oceaneering’s scope includes the full development of Tyra’s integrity management program, developing risk-based assessments (RBAs) that will enable effective and optimised inspection and monitoring for all pressure systems and piping, topsides and jacket structures as well as pipelines.

Managed from our Aberdeen office, Oceaneering will use a multi-disciplined team of corrosion, inspection, structural and pipeline engineers, with specialist experience in delivering large-scale integrity scopes.

Bill Boyle, Senior Vice President for Oceaneering’s Asset Integrity business said:

“We are working collaboratively with Total to ensure that the Tyra Redevelopment becomes a world-class operating facility. This project is defining the way in which integrity management is delivered, and our full suite of services will help to accomplish Total’s goal of enabling remote operations of the future platform.”

In addition to the Tyra Redevelopment, Oceaneering provides a range of other services to Total, from topsides inspection management services in the UK North Sea to ROV, tooling and survey support globally.

Tyra, in production for over three decades, is a unique field. It processes 90 percent of the Denmark's gas production. Redevelopment not only secures production at the field for the next 25 years, but the infrastructure will enable operators to pursue new gas projects in the northern part of the Danish North Sea.

At peak production it is expected to produce the equivalent of supplying 1.5 million Danish homes with gas. The investment in this project is the largest of its kind within the Danish North Sea.

Oceaneering’s Asset Integrity business provides integrity management capabilities, conventional and advanced non-destructive testing (NDT) and specialist inspection solutions, with a team of over 2,100 technically focused people, servicing customers from 24 global locations.

 

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Geologists at the University of Aberdeen have discovered a huge swathe of the North Sea left unexplored for oil and gas because of so-called 'phantom' volcanoes they have proven don't exist.

The study from geologists at the University of Aberdeen has raised the prospect of new oil and gas finds in the North Sea.

The 7000 sq km area, known as the Rattray Volcanic Province, was previously thought to contain the remains of three volcanoes that erupted 165 million years ago, when the North Sea tried to create an ocean between itself and Europe - a ‘rifting’ episode geologists have described as a failed ‘Jurassic Brexit’ attempt.

For decades it was assumed that the area contained the empty remains of old magma chambers, ruling out the possibility of oil and gas discoveries.

However, a study led by Dr Nick Schofield and PhD student Ailsa Quirie from the University’s School of Geosciences, with colleagues from Heriot-Watt and the University of Adelaide, has overturned this view.

Dr Schofield explained: “Building on methods we have used to look at prospectivity in volcanics elsewhere in the UKCS, we combined 3D seismic data donated to us by Petroleum Geo-Services (PGS) with well data to take a fresh look at the Rattray Volcanic Province.

“What we found has completely overturned decades of accepted knowledge.  Previously, it was believed the area contained old magma chambers - the plumbing systems of three Jurassic-era volcanoes – that effectively ruled out the potential for oil and gas discoveries.

“However, our study has shown these volcanoes never existed at all, and that the fireworks preceding the North Sea’s attempt to create an ocean with Europe came via a series of lava fissures. 

Essentially this gives us back a huge amount of gross rock volume that we never knew existed, in one of the world's most prolific regions for oil and gas production"Dr Nick Schofield

“Essentially this gives us back a huge amount of gross rock volume that we never knew existed, in one of the world’s most prolific regions for oil and gas production.”

The study’s findings raise the prospect of future discoveries in the area, which has been left untouched over 50 years of exploration activity in the North Sea.

“There is a huge area under there that hasn’t been looked at in detail for a long time, because of the previously incorrect geological model,” Dr Schofield said. 

“That’s not to say that exploration wouldn’t be challenging, but technology is constantly improving and there are still big discoveries being made in the North Sea, as we’ve recently seen in the Central Graben and Viking Graben areas.

“As the old saying goes, often the best places to look for oil are in places near to where you’ve already found it, and the North Sea is a prime example of that.”

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The BHP Board has approved $696 million (BHP share) in funding to develop the Atlantis Phase 3 project in the U.S. Gulf of Mexico. This follows sanction by BP, as the operator, of the Atlantis Phase 3 project, announced in January 2019.

The BHP Board has today approved US$696 million (BHP share) in funding to develop the Atlantis Phase 3 project in the US Gulf of Mexico. This follows sanction by BP, as the Operator, of the Atlantis Phase 3 project, announced in January 2019. 

Atlantis Phase 3 is located in the deepwater Gulf of Mexico, approximately 130 miles (208 kilometres) off the coast of Louisiana.  The Project is a subsea tie back of eight new production wells that will be drilled and completed to access infill resource opportunities. It will take advantage of existing infrastructure, production ullage and marketing agreements.  First production is expected in the 2020 calendar year and is estimated to increase production by ~38,000 barrels of oil equivalent per day (boe/d) gross at its peak.

BHP President Operations Petroleum, Steve Pastor, said: “The Atlantis Phase 3 project provides a competitive opportunity to deliver on our strategy to grow resources in Tier 1 conventional deepwater assets. The project will further expand the Atlantis field and will provide cost-efficient, near term volumes.”

BHP holds a 44 per cent interest in the Atlantis field. BP holds a 56 per cent interest. 

The BHP Board has today also approved US$256 million in funding to drill an additional appraisal well (3DEL) and perform further studies in the Trion field in Mexico, to further delineate the scale and characterisation of the resource.

The primary objectives of the 3DEL appraisal well and studies are to confirm the volume and composition of hydrocarbons near the crest of the Trion structure, and study the viability of development of the Trion field. The approved funds are within the forecast BHP exploration and appraisal expenditure budget.

 “A further appraisal well at Trion, following the recent encouraging results at the 2DEL appraisal well, reduces investment risk and adds value to this project. If Trion is determined to be commercial, these funds will also provide an option to potentially accelerate development of Trion” said Mr Pastor.

The 3DEL appraisal well is expected to be drilled in the second half of the 2019 calendar year.

BHP holds a 60 per cent interest (and operatorship) in Trion. PEMEX holds a 40 per cent interest.

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German upstream company is back to exploration in Egypt. DEA is planning to drill 5 to 7 exploration wells in Block 10 during the first exploration phase of 3 years.

The Egyptian Natural Gas Holding Company (EGAS) has awarded one new licence to DEA in its 2018 Bid Round. The East Damanhour exploration block (originally offered as Block 10) is covering 1,418 square kilometres and is located west of the Disouq development leases, where DEA is the operator with a licence share of 100%.

“We are pleased with the award of this licence, which is in line with our ambition to strengthen our business in Egypt,” says Sameh Sabry, DEA’s General Manager in Egypt. “The block is located in DEA’s core region in the Onshore Nile Delta, where we successfully explore the Messinian and Pliocene plays as operator since 2004. The extensive knowledge and experience we gained over the years, the right set of skilled experts and our nearby infrastructure will offer us very good conditions to continue this exploration efficiently”, Sabry adds. 

“The proximity of DEA’s Disouq central processing plant and infrastructure provides us with an operational edge, which would enable accelerated development of any discovered volumes as well as considerable synergies and cost optimizations. In addition, the block offers significant potential in pre-Messinian structures, which is in line with our ambition to further grow in Egypt”, underlines Sameh Sabry.”

 

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Oil and gas companies are making huge savings and boosting safety thanks to a unique industry partnership between leading simulator developer, Drilling Systems and Robert Gordon University (RGU).

The Oil and Gas Institute at RGU is working with Drilling Systems and its innovative drilling, well control and lifting simulator technology to help oil and gas companies identify ways to improve efficiencies and raise safety standards, which in turn is leading to substantial cost savings.

Over the past 12 months, the partnership has worked with several oil and gas companies to help them reduce non-productive time and optimise drilling.

Each client’s project is different, but one of the most popular and cost-effective activities being undertaken is to review, analyse and amend individual company processes and procedures. Often new procedures are written prior to operations, but within the simulator suite at RGU, clients are able to test out how procedures work in practise. This enables potential gaps to be identified long before new procedures are implemented in a live work environment and has helped prevent costs in lost time and ineffective drilling practises. In one particular case, a client changed 74 critical procedures based on what they had learnt on the simulator.

Using the simulators to train and assess competency prior to live operations has also reaped rewards for clients. As well as enabling safer, smoother and more efficient rig reactivations, simulator training is helping oil and gas companies ensure staff competency and improve on-the-job performance. For one customer, non-productive time was reduced by up to 40% following a training programme for new and existing crew members.

Clive Battisby, chief operating officer at Drilling Systems, said: “We are delighted that our unique working relationship with RGU is helping oil and gas companies save time, money and improve safety. 

“Our simulators create an extremely realistic environment, which mirrors the equipment and conditions faced on a rig. In this risk-free setting, operators can practise every day manoeuvres and specific emergency scenarios which test competency, so that when they start work in-the-field they are confident and comfortable with the task in hand and operating at maximum efficiency.

“Our simulators are also enabling oil and gas companies test the effectiveness of procedures for new equipment or process changes in a safe environment avoiding costly mistakes or downtime on a live rig.”

Phil Hassard, Oil and Gas Institute Drilling Simulator Manager at RGU, said: “This is a perfect example of a university and industry working together effectively to raise standards and identify better ways of doing things for the oil and gas sector.

“Thanks to simulator technology, our clients have potentially saved millions of dollars this year alone through improved efficiencies and have reduced non-productive time significantly. Working closely with Drilling Systems has also enabled us to develop innovations such as decommissioning simulators and mobile training units and we anticipate this relationship to continue. Together we can ensure the sector has well trained, highly competent workers, well equipped for the needs of the industry moving forward.”

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Peak production expected to be 700 million cubic feet of gas per day.

BP today announced first gas production from the second stage of its West Nile Delta development offshore Egypt.

The project, which produces gas from the Giza and Fayoum fields, was developed as a deepwater, long-distance tie-back to an existing onshore plant.

The successful start up is the second in a string of new upstream major projects expected to be brought on line in 2019 for BP.

Bob Dudley, BP chief executive, said: “This important project start-up benefitted from the excellent working relationship between BP and the Egyptian government. We simply could not have delivered it successfully without the steadfast support of the Minister of Petroleum, his excellent team and the entire government.

“With the second stage of West Nile Delta now online, BP has now safely brought 21 new upstream major projects into production over the last three years, keeping us on track to deliver 900,000 barrels of oil equivalent per day by 2021.”

 "This important project start-up benefitted from the excellent working relationship between BP and the Egyptian government. We simply could not have delivered it successfully without the steadfast support of the Minister of Petroleum, hisexcellent team and the entire government."

 "With the second stage of West Nile Delta now online, BP has now safely brought 21 new upstream major projects into production over the last three years, keeping us on track to deliver 900,000 barrels of oil equivalent per day by 2021."
 
The West Nile Delta development includes a total of five gas fields across the North Alexandria and West Mediterranean Deepwater offshore concession blocks. It was originally planned as two separate projects, but BP and its partners realized the opportunity to deliver it in three stages, accelerating delivery of gas production commitments to Egypt.

Stage one of the project, which started producing in 2017, included gas production from the first two fields, Taurus and Libra. 

The Giza and Fayoum development, which includes eight wells, is currently producing around 400 million cubic feet of gas per day (mmscfd) and is expected to ramp up to a maximum rate of approximately 700 mmscfd.

The third stage of the West Nile Delta project will develop the Raven field. Production is expected in late 2019.

Hesham Mekawi, regional president, BP North Africa, added: “We are proud to have worked with the Egyptian government to deliver this multi-phase, complex project, which plays an important role in both Egypt’s gas supply and BP’s strategy. Our story in Egypt now stretches back for more than half a century and, thanks to projects like this, it has a bright future. Production from Giza and Fayoum will sustain local energy supply and keep us on track to triple our net production from Egypt by 2020.”

When fully onstream in 2019, combined production from all three phases of the West Nile Delta project is expected to reach up to almost 1.4 billion cubic feet per day (bcf/d), equivalent to about 20% of Egypt’s current gas production. All the gas produced will be fed into the national gas grid.

BP has an operating stake of 82.75% in the development.

The start-up announced today in Egypt is the second major project for BP in 2019, following the Gulf of Mexico’s Constellation development, which BP has a 66.6% non-operated stake in.

Separately, the Atoll Phase One project started-up in 2018.  After almost one year of production, Atoll continues to produce 350 million cubic feet per day from three wells, feeding the country’s national grid. A fourth well will be drilled later in 2019 to underpin the deliver of the field’s recoverable resources.

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Challenges remain as deepwater sector regroups after downturn according to global natural resources consultancy Wood Mackenzie.

The global offshore upstream supply chain saw signs of recovery in 2018, and this looks set to continue in 2019, according to global natural resources consultancy Wood Mackenzie. As project FIDs increase, demand for equipment and services are buoying the prospects for the upstream supply chain.

But the downturn left its mark on the sector. Projects remain leaner and phased, and cost discipline remains high on the agenda. The supply chain continues to focus on compact, modular and standard solutions as operators seek the shortest cycle times.

But can this be maintained as the market improves?

Subsea demand increasing, but new supply challenged
Mhairidh Evans, principal analyst, subsea supply chain, said: “Demand for subsea equipment is one of the best leading indicators of offshore market activity. Volumes are recovering and Wood Mackenzie expects an approximate 40% increase in 2018 in comparison to the previous year.

“It’s likely that demand will remain steady for the next few years, averaging about 300 subsea trees per year, an encouraging sign for the sector.  

“The supply side story has evolved too. Consolidation was necessary to survive the down cycle, which represented the lowest demand floor and longest depressed market in recent history. We estimate subsea manufacturing capacity reduced by 25% simply by closing plants and re-distributing resources.

“The result is manufacturing plants that can tighten much quicker than before, even with the smaller, more efficient operations that today’s projects demand.”

She added: “Key operators in the subsea space are becoming aware of this shift in the market. Procurement teams and category management will need to strategise internally and with their preferred suppliers, preparing for anticipated price inflation and potentially increased lead times.

“While the subsea market as a whole remains oversupplied still, another busy year in 2019 will change that. We think the window of opportunity to lock in preferential conditions in 2019 is dwindling and this will be more pronounced as we edge closer to 2020.”

Floating production revisiting historic highs 
Demand for floating production, storage and offloading vessels (FPSO) should be near the highest seen since before the downturn. Adopting modular and standardised FPSOs in shipbuilding lends itself to cost savings and efficiencies – ideally suited to operators looking to scale down and reduce costs.

Catarina Podevyn, senior analyst in Wood Mackenzie's upstream supply chain group, said: “Overspending is a thing of the past. Despite the market’s recovery, we expect development budgets will have to stretch further than ever.

“Operators will be under added pressure to maintain project discipline, and we can expect to see alternative contracting models that reduce technical and financial risk to operators and optimise efficiency.”   

She added: “We expect a higher uptake of the build-own-operate-transfer (BOT/BOOT) contract models. With this approach, operators lease an FPSO at a higher rate before buying it outright. This frees them form the upfront financial risk that would normally accompany a turnkey approach.  Contractors, however, take on project execution risk and must hit deadlines or face losses. We expect this will prompt more sub-contracting, particularly with many FPSOs nearing award.” 

Opportunities for competitive floating rig rates remain
It’s been a buyer’s market in the offshore rig segment, as operators hold contracting power for all but the ultra-deepwater, harsh environment rigs, where supply is limited. Day rates for floating rigs stayed low in 2018. How long will this last?

Principal analyst, drilling and rigs market, Leslie Cook, said: “Despite encouraging signs indicating the potential for higher demand, we believe day rates will remain low throughout 2019.

“Because of low day rates, drilling contractors have preferred short-term con-tracts, hesitating to lock in assets on longer charters. Market utilisation hovered near 65% on continued rig oversupply. This, coupled with rig owners needing to bid aggressively for contracts or else see their assets idle, will keep rates for most rig types low.”

Ms Cook added: “However, exploration is increasing. That, together with the likelihood of further consolidation among rig contractors and older assets being taken off the market, should drive market fundamentals to a point where day rates begin to rise appreciably towards the end of the year. We expect the rig market to balance out in 2020.

Source: Wood Mackenzie

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Total has made a significant gas condensate discovery on the Brulpadda prospects, located on Block 11B/12B in the Outeniqua Basin, 175 kilometers off the southern coast of South Africa.

The Brulpadda well encountered 57 meters of net gas condensate pay in Lower Cretaceous reservoirs. Following the success of the main objective, the well was deepened to a final depth of 3,633 meters and has also been successful in the Brulpadda-deep prospect. 

“We are very pleased to announce the Brulpadda discovery which was drilled in a challenging Deepwater environment”, said Kevin McLachlan, Senior Vice President Exploration at Total. “With this discovery, Total has opened a new world-class gas and oil play and is well positioned to test several follow-on prospects on the same block.”

Total drilled this exploration well with the latest generation drilling ship and was able to leverage its experience in similar environments, such as the West of Shetland, UK. 

Following the success of Brulpadda and confirmation of the play potential, Total and its partners plan to acquire 3D seismic this year, followed by up to four exploration wells on this license. 
The Block 11B/12B covers an area of 19,000 square kilometers, with water depths ranging from 200 to 1,800 meters, and is operated by Total with a 45% working interest, alongside Qatar Petroleum (25%), CNR international (20%) and Main Street, a South African consortium (10%).

The news of the discovery came as Total beat profit expectations in the last quarter of 2018 on record levels of oil and gas production. Total’s net adjusted profit increased 10 per cent in the fourth quarter to $3.2bn, ahead of analyst expectations of closer to $3.1bn. Total’s full year profit jumped 28 per cent to $13.6bn. Production increased 8 per cent at 2.8m barrels a day while cash flow was up 18 per cent at $26.1bn. 

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Technologies such as artificial intelligence, data analytics and edge computing are now allowing pipeline safety and security to be improved

Pipeline companies use a wide variety of methods to monitor pipelines – from highly advanced technology to patrolling the pipeline right-of-way. Visual inspections are done regularly – either by walking, flying or using drones – and the industry also uses electronic monitoring from high-tech control rooms and patrols inside the pipeline.

But technology is now coming online that can advance the practice, moving from traditional alarm-based systems to a more autonomous agenda utilising the benefits of Artificial Intelligence (AI). There are a myriad of challenges facing pipeline operators complicated by the remote nature of much of the infrastructure and the ageing pipeline system that has a lack of continuous visibility. Operators need to safeguard this infrastructure against vandalism and damage as well as ensuring safety and environmental compliance.

One company at the forefront of asset intelligence for remote infrastructure is California-b ased Atomiton. Its system can continuously monitor remote pipeline integrity through multi-sensor data integration that allows modelling of vital equipment such as flowmeters and valves. By utilising AI and edge computing it can detect and alert central operations to potential issues such as leaks, corrosion, freezing damage or vandalism. It also allows operators to capture and analyse remote operations through image analytics. But above all it adds intelligence by predicting and optimising  pipeline maintenance and integrity.

“Detecting something happening to the pipeline has been a solution sought for a long time mostly because they are remote,” Jane Ren, founder and CEO of Atomitonexplains. “We do not always want to send
people there: when something happens, it is usually very srious and sometimes can have catastrophic consequences.”

She explains that one of the biggest issues with pipeline detection is that  traditionally it is threshold based. “You are trying to see an anomaly and if your sound or acoustic signal exceeded a certain threshold
then there is going to be an alarm on the traditional system.

“The biggest problem with that system is false alarms which means that 80, 90 per cent of the time you get an alarm that isnothing significant. Which in some instances can cause alarm fatigue, where people do not
respond.”

Adding intelligence
That scenario is now changing thanks to the maturation of AI. “From the technology perspective we see a growing number of sensors used in pipelines which means there is a growing volume of data which AI can help us interpret and gain insights from,” Ren says. “We recently applied our technology to one of the large natural gas companies that run pipelines here in the US. For this we did not rely on the traditional simple threshold-based system, but we used artificial intelligence of pattern recognition to differentiate the different vibrations: threedimensional vibration patterns of different things happening on the pipeline.”

There are numerous factors that cause false alarms on pipeline monitoring systems but one of the biggest culprits is rain. Other common causes are animals walking on the pipe or heavy trucks driving by, causing vibration patterns on the pipe that trigger an alarm. But alarms cannot always be ignored as there are events that need to be detected and acted upon such as vandalism, drilling or hammering or other damaging impacts on the pipeline.

“When we apply accelerometer and vibration AI on the edge for pipelines, the algorithm can detect that these threedimensional images or patterns are very different between the types of impacts and can detect with high confidence on over 80 per cent of the incidents,” Ren says. “Not just, is something happening, but what is happening? Is it raining or vibration or is it something or someone trying to damage the pipeline? That is a significant difference between how those things can be detected using AI compared to traditional sensing and monitoring methodologies.”

Although there is a great deal of commonality between monitoring requirements, there are also some challenging differences which means that any solution aimed at this sector does require the technology or solution to be versatile to allow it to integrate a variety of different sensors. “If you want to just read the meter at the regular level you can simply utilise a camera along with a visual analytic tool, but if you want to detect a gas leak you may need to deploy some specific sensors that can detect gas molecules,” Ren explains. “On the other hand, if you wanted to detect vandalism you might want to use a vibration sensor, or an accelerometer. For flow analysis you would need to use sonic or ultrasonic sensors. You may even want to triangulate with multiple signals to make sure your detection is validated with more than one type of data.”

When it comes to sensors, the majority are added as part of the solution, although existing ones can be integrated. “We choose multiple different types of sensors depending on the customer need, the dimension or the nature of the pipeline and other requirements such as cost,” Ren adds. “We integrate them into our technology and provide the complete solution to the customer.” 

Adding a digital profile
When it comes to improving visualisation through modelling devices Atomiton utilise a digital twin concept. However, Ren is keen to emphasise that it is not a static digital twin, but a dynamic digital profile or model. “This means that you can get the latest information from gauges and meters as frequently as you want, and continuously update the profile” she says. “This can be by second, minute, day or by week, you can control it. This continuous profiling provides real-time operations intelligence.

Older or analog equipment can also be digitized. There is no need for people to read and record the data manually, because AI on the edge solution handles it. It uses image analytics to learn how to read those gauges and meters, which is often far more accurate than human readings. Whenever there are errors in alarms systems it is often humans’ mistakes in terms of the reading capabilities.

“Interestingly this is not a single dimensional problem either, because there are numerous kinds of meters and gauges out there utilising dials and numerical displays. The AI programme can first tell which type of meter or gauge it is and then read the numbers or dials and create a digital profile. It will decide what significance that data has and where it needs to be sent; some data feeds down into the billing and ordering system and others to operations or maintenance.”

Image analytics
There are several different applications where you would want to use imaging technology to add intelligence to remote assets and operations. One of them is simply to inspect the infrastructure which includes the pipelines to read the meters and gauges. The second type is more involved and is where you can use images to monitor any deformation of the infrastructure. In this scenario the image can define the baseline profile of the infrastructure, such as a tower or pipeline. “This goes back to the AI algorithms that we deploy and use,” Ren explains. “The software can learn the shape and the colour. After a certain level of intensive training, or machine learning, once the shape and colour changes significantly, it can detect the difference. You maintain the baseline, it can detect what has been compromised or different. Of course, image analytics can also be used for people. You can use the technology to confirm that the right people are in the right places, wearing the correct safety equipment and operating in a safe manner.

“One further benefit is the ability to optimise field personnel visits and schedule with real-time visibility of infrastructure integrity. The real-time visibility of infrastructure integrity is critical to safe operations, as are reducing the cost of inspection and reliability of the infrastructure inspection and reducing human errors in meter and gauge reading. But the real upside of that value, is the availability of real-time product flow and imagery information that will be available for analytics.

“For image analytics where we identify people, certainly, that benefit is with the safety and security and just the impact of the workers for the industrial operations. The other benefit of intelligent infrastructure is to avoid environmental compliance issues or violations. It’s not just about interpreting. For example, we’ve deployed a digital silt fence at a construction site for one of our customers because if any violation happens, the fine from the environmental agency here is about $40,000 a day. That’s a very tangible economic benefit when you have a continuous visibility in your infrastructure.”

Beyond natural gas pipelines, there are other pipeline operations that have similar problems. For example, in an oil pipeline, you would want to analyse the flow and improve corrosion, as well as identify and pinpoint potential leaks. Different sensor types and devices may be integrated with the software to build digital profiles, and then used to predict and optimize pipeline maintenance and integrity.

The benefits of leveraging AI for remote intelligent infrastructure is clear, offering the ability to optimise performance, monitor integrity and reduce both safety risk and environmental impact. Combining intelligent algorithms with an end to end solution that integrates sensors with real-time edge computing for profiling of assets and activities is the future for pipelines and it is here today.

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