Intelligent wells aren't routine yet, but industry acceptance is growing.

So often the oil industry comes up with a great new idea - often with a great name to match - and then spends the next decade lamenting the fact that nobody is actually interested in using (paying for) the technology.
Until recently this was the case with intelligent completions. Folks spent hours in technical sessions debating the actual definition of an intelligent completion. Service companies spent hours behind closed doors trying to determine their own trademarked version of the common concept. And magazine editors had a field day describing the potential contributions of this amazing technology to an aging industry.
But the few companies who actually stuck one of these things in the ground often found system reliability hadn't yet caught up with the hype.
A funny thing has happened with intelligent completions in the past couple of years, however. Suddenly these systems are being installed, if not routinely, at least with a degree of regularity that suggests industry uptake is on the rise. Why? Improved reliability is a major factor. There's also been a concerted effort on the part of the service companies to offer a range of systems rather than assume every completion needs every bell and whistle available. And increasingly, the industry is beginning to understand the benefits of intelligent completions extend beyond workover savings and ultimately may be among its best tools for field optimization.
Intelligent offerings
Downhole monitoring equipment is nothing new. The intelligence comes when the information from downhole can be acted upon without hauling in a workover rig. "When people first started talking about intelligent wells, it was very much focused on the surface-controlled flow controls as the thing that was a big advance," said Graham Makin, marketing director of intelligent completions for Weatherford Completion Systems. "But nine times out of 10, to make proper use of those controls you need permanent monitoring anyway. So the two kind of go hand in hand."
Many companies have found they can readily adapt existing technology to come up with a surface-controlled system. Osca, for instance, uses straight hydraulics to control sleeves downhole.
"Integrating the entire completion system allowed development of a completely interventionless system. No mechanical intervention is required during completion or production operations," said David Walker, product line manager for completions tools. "Sleeve development utilized proven technologies in both sealing and sleeve actuation. We took our existing mechanical sleeves and added hydraulic actuation."
Weatherford also has focused its control efforts on hydraulics, and through its purchase of Cidra, it's focusing its sensing efforts on fiber optics. "In an electronic system, there's a lot of really critical components run in the well itself," Makin said. "An optical system is very simple. The components run in the well are electronically passive, and all of the clever, complex stuff happens at the surface."
This is of key importance because of the life expectancy of these systems. While much of the important data acquired in a field is obtained within the first few years, there's also a critical period 10 or 15 years later where the final efforts toward field-life extension also require good data. "We're aiming to produce a good-quality data stream for the field life, not just in the period at the start," Makin said.
Other companies are having success with more complex systems. Baker Oil Tools has been working on its intelligent completions initiative since 1995.
"We asked a lot of operators what they would want in the perfect intelligent well system," said Kevin Jones, senior manager of Baker's Intelligent Well Systems Development group. "We got a lot of our specs from that and have developed this very complex but very functional system that gave them the bells and whistles they asked for at the time. We're now seeing that get into the marketplace and are getting a lot of credibility with it."
The credibility factor will only take off as the systems begin to prove themselves in the field, and some won't be called upon to do much for several years. But the industry is beginning to compile a scorecard of intelligent completion successes that's spurring greater acceptance of the technology.
At WellDynamics, a joint venture between Shell and Halliburton, the product offering ranges from simple hydraulic systems to the top-end system, known as Surface Controlled Reservoir Analysis Management System (Scrams). Mike Fleming, chief executive officer at WellDynamics, said the industry is rapidly overcoming reliability problems that may have plagued earlier systems.
"I think there has been a misunderstanding in the past that putting electronics down the hole and increasing the sophistication leads to reliability problems," he said. "Quite often the contrary is actually the case because the electronic systems are redundant. In Norway, there's a belief amongst the operators that the so-called high-end systems are the most reliable and the least likely to give us problems. Complexity doesn't necessarily relate to reliability exposure."
Case studies
Some of the field tests are offering some rather astonishing results. Sashidhar Rajadopalan, strategic marketing manager for WellDynamics, told of customers who wanted 10 years of reliability history before deciding to install an intelligent system. But others have been willing to take the plunge without the proof.
"One of the Norwegian operators went with a high-end system and spent quite a lot of money for it," he said. "They made a return on their investment in 18 days. If the decision criteria used by a customer is 10 years, they've inappropriately postponed a decision that could have satisfied the return on investment. If you can make money in 18 days and the system fails on the 19th day, you've still made money."
Other service companies also have had marked success with their systems. Schlumberger, for instance, completed a horizontal section in Indiana as an intelligent completion and demonstrated the well at the recent Offshore Technology Conference in Houston, Texas. The horizontal section is segmented into three parts isolated with packers. Each segment is controlled with monitoring, pressure gauges and a distributed temperature measurement.
"This well is a cross between a showcase and a system that enables us to demonstrate the value that operators get from being able to control this type of reservoir," said Jeremy Walker, marketing manager of testing and completions for Schlumberger.
Shell has about 20 intelligent wells worldwide and is working to increase that number. One of its showcase pieces is a well in the North Sea's Brent field. The well produces oil but also has a perforated gas zone uphole that's opened for a short period each year to meet a gas contract.
Smart fields
Whereas once the technology might have been viewed as a tool to minimize or avoid costly interventions, it's now being realized that the constant flow of information from these wells gives insight into what's happening at a reservoir level and can even be helpful while a field is still under development.
At Shell, intelligent well technology is important enough that the company has established an implementation group that travels the globe encouraging Shell's business units to consider the technology. "People need to be satisfied with the reliability question," said Carlos Glandt, smart wells global implementation manager for Shell. "But there is also an issue of value. If the value is clearly identified up front, then we can talk about the risk.
"Early in this process, this was only driven by well engineers and completion engineers who were excited about the technology but unsure about the risk. When you bring the subsurface community to the table, you bring the value, and by bringing the value you can understand the risk in a better context."
Part of the risk reduction is realized through cycle-time reduction, said Arun Sharma, director of reservoir solutions for WellDynamics. "In the past, there was a large lead time in between collecting data and being able to make a decision and act upon it," he said. "The loop between monitoring, decision-making and actually changing something downhole was weeks if not months. With a smart well in the ground, that cycle time can be reduced to a day."
Charlie Cosad, a marketing manager for Schlumberger, said that loop consists of several steps. First is monitoring - simply plotting data against depth, time and events taking place in the well. Next is surveillance, where data is validated and compared to models. Then comes diagnosis, which requires more human intervention as changes in data are ascribed to a particular problem or event. Then comes acting upon the data, or "optimization."
Monitoring and surveillance can be almost completely automated, and some pundits predict a truly "smart" well will make many of its own diagnostic and optimization decisions eventually. For now, some of the hurdles include capturing this massive amount of data in such a way that useful decisions can be made.
"Production data is a very different world from the episodic world of well construction," Cosad said. "What does real time mean in the production phase? You've got large volumes of data, you have trends, and you're going to be very rigorous in looking at costs on bandwidth and information technology infrastructure and all of those things.
"A lot of the places where we see the opportunities are in the mature fields, where of course you've got a lot of existing infrastructure and legacy systems. We'll need to be able to integrate with what's there because that's a huge opportunity for the industry."
Added Jones, "There are some operators saying, 'That will never happen in my well. I don't want a machine shutting off my well.' That's probably going to be the biggest leap of faith - the operators turning over the production of a reservoir to a computer."
Ultimately the vision, said Makin, is to move from intelligent wells to intelligent fields. "My spin on that is we're already starting to get there," he said. "If you look at a big North Sea platform, you've got a fairly complex process plant that takes oil out of the well, separates the water, separates the gas, compresses the gas and exports the produced fluids. There's a closed-loop control architecture to monitor and optimize this production system. To a certain extent, I think what they're driving at is to take that topsides process system and integrate the well into it."
Added Fleming, "The right level of smartness for a reservoir includes drilling the right number of holes in the right places. The old way might have been 20 verticals, and the new way might be three horizontals with laterals.
"Our reality today is playing a role as leaders in smart wells but with an eye for how to integrate, how to have open systems, how to manage data, how to sift through it and how to remain compatible to ensure that the investments we make are going to converge on the big game."

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