Special Report Contents

• Comment: Grim 2016 for producers
• Oil price forecasts make for a bleak 2016
• Egypt’s game-changing gas find
• The most important energy project in Iran
• Amec Foster Wheeler seeks growth in the Middle East

If you were looking for the future of oil production monitoring and control, you probably would not begin above an eclair shop in an under-frequented shopping mall in Kazakhstan.

But that is where you would end up: in the Almaty Control Centre for the Asia Gas Pipeline (AGP).

Far from the mountains where the pipeline itself runs, a giant bank of screens occupies a wall of the control room, shining its data around the clock over rows of computers where engineers continually monitor and control the 2,000-plus kilometres of infrastructure transporting fuel to China.

Digital oil fields

These engineers seldom venture into the field; rather, they use the system to check pressures, temperatures, valve flows, blockages, breaches and anything else that can go right or wrong.

They can check and control the pipeline’s whole system, from bypassing faulty valves to injecting methanol to thaw blockages caused by frozen condensate during the cold winters of central Asia.

The state-of-the-art centre was put on display during Chinese technology firm Huawei’s Global Energy Summit 2015 in Almaty.

The event served as a showcase for stakeholders and evangelists of digital oil fields, the systems of high-tech monitoring and control that allow oil companies to watch and remotely manipulate their assets.

Cutting expenses

Digital oil fields offer benefits in several areas. Expenses can be saved in health and safety, transport and staffing costs. Wells can be made more efficient through fine-tuning, with failures caught faster, better collaboration between stakeholders and more comprehensive modelling.

Hatem Nasr, a consultant for organisations that include a US manufacturer of pumps, Huawei and Kuwait Oil Company (KOC), and a speaker at the summit, is adamant the industry needs to go digital now.

He cites an unnamed major oil producing country in the Middle East where he says 80 per cent of wells are unmonitored. “I’m not talking about a well in West Texas that produces 40 barrels a day [b/d],” he says. “This is a well that produces 4,000 [b/d].”

One field can have thousands of wells, and when these must be checked by hand – literally; engineers often touch the pipes to see if a well is producing – that is a lot of time in the desert. The number one health and safety cost, says Nasr, comes from people driving to the fields.

In winter, lower temperatures threaten a build-up of hydrates in the pumping systems. “[With the KOC smart field], I can turn off my wells remotely; my people don’t even have to go,” says Nasr. “Just by doing that, in one year we got $75m [in savings].”

 Real-time modelling

Through the monitoring of wells and their surrounding geological and seismic conditions, detailed, real-time models can be built up to allow analysts to better tweak variables and optimise production.

At the Huawei event, Nasr showed his audience a picture of engineers gathered around screens, to demonstrate how this monitoring and collaboration work in practice.

“They get together in one big room,” he says. “My reservoir people are sitting in the same room. People are sitting across the city. Operations guys are in the field. My field development guys are sitting together. Everybody is sharing information.”

The system can show which wells are facing major problems, and those where production can be increased.

“How does the system know?” asks Nasr. “ [Through] the real-time data, the models. It ran the models so I can say: ‘Based on my model we are here, but I could be doing much better.’ The system tells the operators to increase the frequency from 46hz to 51hz and that will give you 500 more [b/d]. If I have thousands of wells, this is going to give me more oil every day.”

“This is for us, the technology junkies, the Holy Grail,” he adds.

Hi-tech connectivity

Smart oil fields incorporate systems to collect data on location, transmit that data and process it into a format that can be used to make educated decisions.

Until recently, fibre-optic cables were the transmission system of choice, along with radio and satellite. But cables are prone to outages if they are broken or cut, and are hard to expand as networks grow.

Older wireless systems can transmit only limited volumes of data. Hi-tech, high-speed Long-Term Evolution (LTE) communication, however, is now cheaper than the UHF (ultra-high frequency) radios traditionally used to communicate with engineers in the field, so 4G connectivity is set to become the new norm.

When engineers are on site, they can link to the system to see readings and models on a portable tablet computer.

Cloud technology

Data analysis is being better enabled by a combination of faster computers and cloud technology. Rather than processing data either at the wellhead or back at base, it can now be crunched in the cloud, and the results of modelling scenarios, for example, passed back to operators quickly.

In the past, it might have taken weeks to process a field model, even using a supercomputer. Models used by KOC, with 200 million data points, would have taken six months to crunch. With cloud processing, the same models can today be delivered on a laptop in only six hours.

The Middle East oil and gas industry is “very late to lots of games,” says Nasr.

Return on investment

KOC, however, has embraced digital field technology and found that it quickly saw a return on its investment. One component, a $60m smart completion project, paid for itself within eight months. Within a year, it had saved the company $80m.

Estimates of how much smart fields can save oil companies vary depending on whose reports you read. “Everybody talks about somewhere in the range of improved recovery of 7-8 [percentage points],” says Nasr. “I am very happily satisfied to take it to 4-5 [percentage points].”

Recovery rates for oil fields are typically about 40 per cent; for every 100 barrels of oil in the ground, 40 can be extracted.

Raising this rate to 45 per cent globally will make a difference of “not billions, but trillions of dollars”, says Nasr.

And it is becoming more necessary. In a time of declining production, digital oil fields allow producers not necessarily to raise their output, but merely to stem their decline and reduce their operating expenses.

Water ratio

In many of the region’s wells, the water cut – the ratio of water to oil extracted – is rising. “In some of the most prolific fields, everything is changing; [there is] a severe decline,” says Nasr.

“I’m talking about a 15-20 per cent decline. Before, we used to see 6-7 per cent annual decline, but water is increasing, going from 5-6 per cent water cut to 22 per cent water cut.”

Some Omani fields are running a water cut as high as 90 per cent, and Nasr calls these ratios “cataclysmic”. Petroleum Development Oman (PDO) has been using smart fields for several years.

Digital oil fields reduce uncertainty and better predict what changes are coming and what effect changing variables will have on production and transmission.

Two of the major hold-backs to the adoption of digital oil fields are change management and security worries.

Computer viruses

In 2012, state oil firm Saudi Aramco succumbed to a virus that erased data on three-quarters of its corporate personal computers. The company was forced to shut down its internal corporate network, disabling email and web access before replacing hard drives on tens of thousands of computers.

Nasr says wireless networks are as secure as wired ones, and national oil companies (NOCs) hide behind security concerns to mask their innate neophobia.

But his peers are more measured. “It’s like if one thief gets into your house,” says Muhammad al-Dhamen, senior information technology consultant at Huawei, who was working at Aramco when the attack happened.

“Your family will be concerned all the time about whether the door is closed or not, whether the security system is on or not.”

Al-Dhamen says NOCs are hesitant to become early adopters in case they open themselves up to becoming early victims too. “[Aramco] is slow in adoption because it wants to see KOC do it, the UAE doing it, then it will jump in,” he says.

“Or vice versa: other people will wait for Aramco and then they will go ahead and move.”

Accurate models

As smart oil fields evolve, the future will see closer monitoring of the various elements within a field. It means for instance that a company will be able to monitor water moving through a 3D model of the field’s whole surrounding area, rather than just measuring it at each wellhead. This allows the creation of more accurate models, giving an even more detailed picture of what is going on.

As well as being able to see the state of wells, says Nasr, engineers will also be able to monitor seismic and microseismic data, tracked with sub-surface monitors.

It means analysts will be able to check if water cut from a well is increasing and model what effect changes to pump controls will have, as well as track the movement of floodwater through the whole field.

In the meantime, making sure people can use the information available is the other hurdle to a wider and faster adoption of digital oil field technologies.

Productive usage

“Productive use of information is also critical,” says Phil Milette, senior consultant with the US’ Honeywell, a partner on the AGP project.

“If the receiving of that information, the amplification layer, is not equipped to most productively use the technology provided then it is technology investment that’s not really giving the right returns because of lack of productive use.”

Nasr agrees. “One of the biggest challenges we have is change management,” he says.

“You need to get people used to the idea, train them on how to use the system, get the whole culture changed.”

Even persuading siloed sections of an oil company to collaborate is not easy, but it will come.