Proyek Shell Snake Well

As the oil and gas industry scrambles to meet growing worldwide demand for hydrocarbons with a workforce diminished in experience and tight resources, producers have been forced to develop and operate their fields in more innovative ways. This mandate is at the heart of the Smart Fields initiative, Royal Dutch Shell’s ongoing technology program that aims to maximize production and over-life value while driving efficiency gains.

According to Shell’s 2005 Global Energy Scenarios report, worldwide hydrocarbon demand will grow by an extra 120 MMBOEPD by 2025, and the recently released Medium-Term Oil Market Report from the International Energy Agency predicts global oil demand to rise by an average of 2.2% per year until 2012. In order to meet this demand, producers will need to extract more hydrocarbons from existing reservoirs and increase production from unconventional reserves (such as tar sands and heavy oil) and environmentally challenging locales (like the Arctic).

Smart Fields technology was created to face these challenges head-on, by employing a suite of skills, workflows and technologies to continually optimize producing assets. Shell has long been considered a pioneer in the Smart Fields concept, so much so that the company even copyrighted the term.

Charlie Williams, Shell’s Chief Scientist for Well Engineering and Production, and Tom Webb, Shell’s Smart Fields Coordinator for the Americas, recently provided an update on the Smart Fields process and gave some insight into where it is headed.

According to Williams, the current suite of Smart Fields offerings is a far cry from what was available or envisioned at the beginning of his career. “I’ve been associated with previous generations of Smart Fields since I started with Shell 35 years ago, and back then it was referred to as ‘computer-assisted operations’,” Williams said.

Shell’s first foray into Smart Fields occurred in the late 1960s at High Island 160, in the shallow Gulf of Mexico waters off the Texas coast. “With this first application, we were really interested in automating and controlling certain rudimentary functions in the surface production facilities. We were using vacuum tube technology there, and we had the whole bottom floor of one of the employee quarters buildings full of all this vacuum tube equipment.”

Smart Fields began to evolve as Shell engineers realized that more could be done than just simple automation. “Much of our onshore production in West Texas and New Mexico was on beam pump artificial lift,” Williams continued. “It was quite apparent that there was much opportunity to not only computer-control, but also to computer-optimize, our operations. So we put in control systems that allowed us to optimize production from each artificial lift well and do automatic well tests.”

Shell’s current concept of Smart Fields started with Smart Wells. The Smart Wells concept has come to mean the design of completions that incorporates downhole equipment to control flow into and away from the well, combined with sensors that measure pressure, temperature, flow, fluid composition and potentially seismic events. The data acquired by these sensors are transmitted to the surface through electrical cable or fiber optics, and engineers then use this data to analyze changes in the reservoir. If needed, optimization decisions are then implemented by sending commands to the downhole flow control equipment.

Shell reports that Smart Wells add value to well operations on several fronts, such as improving hydrocarbon recovery from the reservoirs by as much as 15%; controlling the production of unwanted fluids (water and/or gas); reducing the need for costly well interventions; and providing insurance against any reservoir uncertainties.

The efficiency gains afforded are another big benefit, according to Williams. “In the old days, in order to collect data in onshore oilfields, you had to drive hundreds of miles to each of the wells to collect what you needed… Not exactly the best use of someone’s time.”

Smart Wells technology proves a charm for snake wells

“Another benefit to Smart Wells,” said Webb, “is that you don’t need to drill so many holes in the ground. You can drill fewer wells, but these wells will have a farther reach into more production zones. Actually, that’s where the concept of snake wells comes in.”

Shell’s snake wells, with their tortuous horizontal paths cutting through undulating layers of shale and sand to penetrate a number of producing zones, were perfect candidates for Smart Well control and data gathering. Additionally, snake wells incorporate advanced directional drilling techniques, such as steerable drill bits and software that generates detailed models of underground geology. This allows drillers to hit production targets that are less than 2 m across and miles below the surface.

Snake wells got their debut at Shell’s Brunei oilfields in 2003. The first was at the Iron Duke brownfield, in which a snake well was drilled through an area that was 28 m thick, 2 km long and 300 m wide. In addition, the drilled well had to avoid a nearby layer of natural gas whose pressure drove oil to the producing well.

Shell reports that although the snake well at Iron Duke added complexity and a corresponding degree of risk, the field would not have been economic otherwise. The Iron Duke snake well program reportedly yielded a 15% increase in production and delayed water breakthrough by 2 years.

Since then, Shell has reported similar success with other Smart snake wells drilled on the nearby Champion West field, which tapped 11 separate oil pockets and added over 25,000 b/d of production.

While Smart Wells provide a great deal of data, the natural question for Shell engineers then becomes “What do we do with it?”

Williams explained that the concept of Smart Wells showed Shell the power of being smart beyond the wellbore. “Smart Wells became the foundation that data providers used to build the Smart Field concept. Once we had the Smart Wells, we could move into surface facility control and ultimately total reservoir control. We don’t want to optimize just the wells, but we want to optimize production from the reservoirs themselves. You could extend this concept on to an over-life reservoir control process… I see it as a natural evolution.”

Part of this Smart evolution involved the creation of real-time drilling and production operation support centers. Explained Webb, “These centers allow engineers to see the drilling data on many wells all over the world and make decisions about those different wells in one location, without having to visit them in person.”

Drilling centers like the one at Shell’s Westhollow facility in west Houston are already up and running, and real-time production optimization centers will open soon.

Not only do these centers provide drilling and production data in real time, but they also provide the data in the most convenient form and format for the end user. “These centers accumulate data in a format that enables your analysis and decision making,” Webb continued. “Smart Fields technology then links up what used to be several different modeling and software programs, and incorporates them into a unified optimization system that supports decision making.

“Ultimately, what you see on the screen should be only what you need to see for your job function,” said Webb. “You don’t need to create a lot of different custom reports, because that’s done for you.”

These real-time centers allow team members to be in the same room either virtually or physically, which Webb considers a major benefit given the current shortage of skilled people at all levels of a field operation. “To the extent that you can bring the data and the decisions to the people, rather than vice versa, then all the better. This is particularly true since many people are working on more than one project in more than geographic location.”

Team members can discuss and visualize a project or field system together and then have the results transmitted back for debriefing and review. “It allows for collaboration among groups and really improves your whole project planning and teamwork capability,” Williams added. “Everyone has the same data at the same time in the same place… It’s become an integral part of the work process rather than something you do in your spare time.”

Full Smart Fields success requires new attitudes

Part of Williams’ job during the past 3 years has been to act as a champion of the Smart Fields process, spreading the word through web casts and site visits. “At my talk at the SPE Digital Energy Conference earlier this year, I stressed that Smart Fields should really be thought of as a different way to do your work,” Williams said. “Most people think of Smart Fields only on the hardware and software side, the end elements. These components are really just enablers to allow you to do your work more efficiently. The key is to work in a new way, and allow the computers to enable that work.”

Williams pointed out that it is the work process that is the first critical part of the concept. “You don’t buy the computers first and then figure out how to do the work. You have to decide on the work process first and how that process can add the most value, and then use the Smart Fields to enable the work.”

Another critical component is the people who will be expected to use this technology, and Williams stressed that getting the operations people informed early on about the positive benefits of the system is essential. “Because we are talking about an integrated work process, you have to start with the people in operations first.”

Webb has also been championing the Smart Fields concept through a series of presentations at various conferences like the 2007 Offshore Technology Conference (OTC) in Houston, Texas, U.S.A. It was there that Webb stressed that making an asset ’smart’ takes some up-front planning and forethought on the asset’s production goals.

“Prior to putting any monitors or tools into the well,” said Webb, “you need a careful design methodology that examines those parameters you want to manage really well.”

Webb also stated that because the technology is modular, an operator should use only those components that are worthwhile for the asset. “You should use the right level of ’smartness’ for your particular field location that makes good business sense. Because the components are modular, you can deploy different parts at your particular location without adding unnecessary complexity.”

Where does Smart Fields go from here?

In order to get the full benefit of Smart Fields, Williams and Webb acknowledge that several technical hurdles have to be overcome. “Ideally we want to be able to optimize reservoir performance on a 24 hr/day, 7 day/wk basis using many multiple tools,” said Williams. “The functionality of all the software is not quite there yet to do that.”

This functionality can only come from software packages that seamlessly integrate with each other without the need for complicated interfaces. “Integrated software would definitely help our models and systems work faster, which is what you need when you’re trying to do real time optimization,” Williams continued. “While I don’t think we’ll be doing reservoir simulation every day, I can see a definite need for faster processing on models that need quick decisions, such as those designed to understand slugging and flow assurance in deepwater subsea pipelines. Having the models work faster to analyze a complex system like that would be a great help.”

Webb sees more work to be done in bolstering both databases and documentation. “Getting a truly common database for Smart Fields users on a global basis would be invaluable, but this will be hard to do. Once you have that database, how do you begin to populate it with useful documentation, the kind that will help people understand which processes work the best?”

Even if the right documentation is there, current information systems make the task of finding it too difficult, according to Webb. “Sometimes, you spend 20 to 30% of your time and effort just finding the information, so we will need to improve our systems to let us work more efficiently.”

The last frontier, according to Williams, is improved decision support. “I’d like the technology to help me make better decisions, not just give me the data. However, there is a good deal of work currently going on in this arena, so I’m encouraged.”

Smart Fields benefits fields green and brown

At his OTC address, Webb stated that Shell is planning Smart Fields installations for more greenfields than brownfields, mainly because it is far easier to install and implement this technology from the start rather than retrofitting fields.

Shell is currently running 12 asset programs with more than 25 component projects around the world, and they will soon be joined by several greenfields such as the GOM’s Perdido field in 2009, which will be fully smart. Smart Wells have recently been installed at the Vadelyp oil field in Russia by Salym Petroleum Development (a 50-50 joint venture between Shell and Russian oil company Evikhon), which marks the first use of this technology in Russia.

“It’s interesting how these things come together to support themselves,” Williams continued. “It is really opportune that as Shell is moving into these far-flung and technically complicated projects, we now have these smart tools at our disposal to solve the challenges.”

To learn more about the Smart Fields technology platform, please visit www.shell.com/home/content/technology-en/developing_and_producing/dir_developing_and_producing_14122006.html, or contact Charlie Williams at Charlie.williams@shell.com.