Digital oilfield

Shell Chooses HiberHilo to Improve Well Monitoring

Shell needed an easy-to-use, simple well monitoring solution. Could an IoT wireless solution measure up to a classic wired approach?

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Source: Hiber

Oil and gas wells can last a hundred years, but they don’t last forever. And when a well reaches the end of its life, it needs to go through a decommissioning process to preserve the surrounding area and make sure there is no environmental contamination in the future.

The decommissioning process begins with a one- or two-year diagnostics period before the actual decommission. During this period, engineers gather data about the condition of the well so they can make a plan that eliminates risk after the decommission. Engineers need a lot of data during the diagnostics period, but not all the data can be gathered automatically. To get the information they need, oil and gas companies send teams of engineers out into the field to gather the data.

Shell understood the hassles of decommissioning, and knew there had to be a better, safer way. And when the company’s engineers heard about a simple solution for remote pressure and temperature monitoring called HiberHilo, they figured it was worth testing.

Baby-Sitting Wells Entails Expensive Manpower

An oil or gas well leak or blowout is a disaster—for people’s safety, environmental impact, and the commercial impact both locally and globally. Which is why well monitoring is a vital part of every oil and gas operation—especially since 33% of wells will encounter an integrity issue at some point in their life.

For onshore sites that are close to populated areas, monitoring generally isn’t a problem. The wells can often be measured by connecting to a local network, or engineers can drive out and conduct tests. But remote onshore wells or unconnected offshore wells are a different story. There’s no simple way to monitor parameters like pressure from afar, so teams of engineers are deployed to manually check pressures every few days or weeks.

Sending teams of engineers out on these trips is dangerous. From bad weather, to lack of local security, to simply the remote nature of the locations, there’s a lot that can go wrong.

For offshore platforms, just getting people onto the platform is dangerous and expensive. Many platforms are old, with no safe place to step onto the platform from a boat. Instead, temporary scaffolding or some other access structure must be built for every visit.

Remote onshore wells pose their own challenges, especially in locations where there can be tens of kilometers of open space between sites, requiring an engineer to drive between each well. There’s often no communications network in these situations, and little access to local infrastructure or GSM technology. Which leaves the engineers vulnerable: to the weather, to broken vehicles, and even to dangerous gangs that see oil companies as profitable targets.

It Starts Off Costly and Then Gets Expensive

Remote monitoring occurs in some of the least-connected areas of the world. Which means companies must either build communications systems entirely from scratch, use legacy systems, or hire specialized engineers who know how to work efficiently in dangerous territory. Then, there’s the specialized safety gear, deploying them to the site, and the logistics of personal safety. Sometimes it means shutting down production for a few days.

Often, engineers will be on the platform for just one day, but a trip to visit several sites in one week can cost anywhere from $10,000-$40,000. And it’s a trip that needs to be done regularly, just to keep the wells safe and meet regulations. Trips to onshore wells are less expensive, but often still cost hundreds of dollars.

Another consideration is that adverse weather conditions may prohibit those engineers from visiting the site altogether for an extended period. There are some areas of the world where regular monitoring becomes impossible during certain times of the year: the monsoon season from June to October, when wet, violent rainstorms batter much of Southeast Asia. And when the rain rolls in, it may be months before it’s safe enough to visit a platform and measure pressure.

Hurricanes—which are increasing in frequency—prevent engineers from properly managing wells. When a hurricane builds in the Gulf of Mexico, oil companies must entirely evacuate platforms of people, leaving just skeleton crews essential to production. And if the hurricane is imminent and the platform is in its path, those skeleton crews must be evacuated as well.

Now, wells are tough. Even if there is a months-long period between bleed offs, most wells will withstand any pressure buildup. But it is nerve-wracking for anyone who works in the industry. If the pressure buildup becomes too much, there are risks for leaks—a risk that grows every day that there isn’t a pressure measurement.

Manual Measurements are Insufficient

Besides the expense and the danger, the data collected through manual readings is spotty. Too often, data readings resemble snapshots of the well every few weeks, recorded with pen and paper, rather than actively monitoring the data over time.

Infrequent data collection increases the risk for integrity issues. Because wells are only checked every few weeks, there’s no way of knowing what happens between checks. And that’s dangerous territory, because if there is a well integrity issue, chances are high that by the time it’s discovered, it’s been growing for a few weeks. Engineers can only know what’s happening at a well while they’re out gathering the data. Which means that the other 98% of the time, it’s impossible to know what’s happening at the well.

Engineers are also human, which means they can make mistakes. If the weather is hot, or there are hurricane-force winds whipping around a platform, or even if they’re just tired from two days of travel to a well—these are factors that can lead to bad data.

Updating Monitoring Systems is Challenging

As a safety measure, oil wells typically have multiple annuli that prevent oil or gas from being exposed to the outside environment. Each annulus is a ring around the production tubing that has a specific job; they all work together to maintain pressure on the tubing and serve as barriers between the oil and the outside world.

Pressure is one of the most important parameters for monitoring annuli. The pressure should always remain constant, so if there are any pressure changes within any of the annuli, it could be a sign of a problematic down-hole leak.

Many oil companies want to expand or upgrade their current monitoring systems, but there’s no easy way to build out this expansion. It means shutting down the existing monitoring system and physically plug new pieces with wiring into the system. It’s expensive and dangerous—and requires permits, engineering hours, and rigorous checking.

For older systems, a slight twist in a wire may break the whole monitoring framework. Meaning you lost crucial engineering and production hours just to create a more expensive and dangerous problem.

Some platforms and onshore sites already have some type of monitoring in place, typically through a wired connection. These systems can be decades old though, and they may not measure everything you want to know.

Satellite Technology Changes Everything

The Nederlandse Aardolie Maatschappij (NAM) and Shell wanted a better way to monitor well integrity. In a joint project, the companies tested a new, satellite-connected solution on a well awaiting abandonment that was still connected to a pressure monitoring system.

The purpose of the test was to evaluate the speed and ease of installation, compare the output of the sensor to an existing wired measurement system, and evaluate the future possibilities of this approach. Both companies wanted a system that was easy to install, easy to use, and easy to trust. Satellite connectivity met all three criteria.

First, the entire installation took less than three hours, with the sensors connecting to the satellites within 15 minutes. The installation was so fast that the engineers estimated they could have done another 15 installations in the same day, making this approach suitable even in remote areas.

How It Measured Up

After some optimization, 99.8% of the data collected at the wellhead was successfully pushed to the central server. Reliability is important, but so is accuracy. NAM and Shell specified that accuracy levels should be within a 10% range of control data provided by the wired system that was installed alongside.

In fact, the accuracy was astonishingly close, with the satellite sensor’s data deviating just 1.87% away from the control data, when compared on a 0-40 bar range. On average, the satellite data was 99.75% as accurate as that of the wired system, according to Shell and NAM.

Shell was so impressed with the satellite-based approach that they decided to move forward with a global framework agreement that lets subsidiary companies and entities transition to satellite IoT as fast as possible.

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