Wave of the future

The process terminal at Nyhamna is on a small peninsula on the northeast side of the Norwegian island of Gossa.Automation is the ideal way to unite technology with company cultures.

Through technology, workers in the offshore environment have the potential to form a myopic view on life. Produce now, don’t worry about tomorrow. It makes sense. From drilling to producing, safety, and compliance, to name a few, they see what their particular job function is and they get down and do it.

That just won’t cut it anymore because to achieve a highly successful operation, companies need to integrate all their technologies and cultures into one cohesive unit.

That is exactly what Norske Shell knew what had to happen.

Deep underneath the harsh seas of the powerful North Atlantic lies the Ormen Lange gas field off the coast of Norway. The field is between 2625ft and 3609ft deep, with the reservoir 9843ft (or almost two miles) below sea level, covering an area 24.9 miles long and 5 to 6.2 miles wide.

The field does not have any conventional offshore platforms, rather it has three subsea templates on the ocean floor connected directly by two 30in. 74.5 mile-long pipelines to the onshore process terminal at Nyhamna, a small peninsula on the northeast side of the island of Gossa off Norway.

The gas from Ormen Lange goes to the Nyhamna terminal, gets processed, and ends up blended with gas from other fields in the North Sea. It is then transported to Easington in the UK via the 718 mile-long Langeled pipeline, one of the world’s longest subsea export pipelines. When it is all said and done, the Ormen Lange field supplies up to 20% of the UK’s natural gas energy.

While developing the field has been the largest single project in Norwegian industrial history, Norsk Hydro, which discovered the field, and then later Norske Shell, which took over operation, knew they needed to integrate a comprehensive automation, safety, and information management system, overseeing all applications for operation, maintenance, planning, and reporting, using a distributed control system with 15,000 I/O.

“This is an extremely large system,” says Arne Røsdal, Norske Shell’s operations support supervisor of Ormen Lange. “Although Norske Shell was involved throughout the design phase, we did not feel we had sufficiently detailed expertise to optimize the system.”

With their partners, Norske Shell decided the automation, safety, and information management solution, would include applications for daily operation and maintenance, as well as planning and reporting. The distributed control system with six operator workplaces and eight engineering stations required 42 servers in six cabinets for the process automation and information management system. The 15,000 I/O mainly worked off HART and Profibus network protocols.

The process ended up monitored and controlled by 67 controllers handling process control, process shutdown, fire and gas alarm, HVAC, power distribution control system, subsea control units, and fire water pumps. Two safety systems for emergency shutdown and anti-surge systems are a part of the system.

At start up in 2007, the facility was bringing ashore and processing natural gas and condensates from 16 wellheads. Three wells were in operation at the time and daily gas production ran at 40mmcm. This corresponds to revenue in the range of $23 million per day for the facility. Unplanned downtime of any kind was unacceptable; uptime remained at a premium.

While this project has continued to grow, this is a solid case of how automation is evolving in the offshore environment.

“Automation can help monitor the flow assurance from these pipes from failing or bubbling or slugging, so they can actually predict from the data, through historic data from wells’ production, or from the flows on data they are collecting on a real-time basis,” says William Mao, vice president of oil, gas and petrochemicals for ABB North America. “With both of those bits of information you can improve well [performance] from as small as 5% or up to 15% or 20% of well production. To an operator that means a lot of money.”

“Automation is allowing you to do more with less people for the health and safety environment on the platform,” says John Oyen, business development manager for oil and gas at ABB North America. “It is expensive to have the people out there and you don’t want them in harm’s way. The better visualization and control of these processes and the integration of the various subsytems and the electrical, fire and gas and safety and subsea control, as you bring that together, allows the operators to quickly make a change to solve a problem.”

Vital function

Automation’s role offshore is becoming increasing important where users need to have an interconnected set of systems, so they can eventually run facilities unmanned, or at least have the opportunity to shut them down remotely when facilities encounter bad weather or other situations.

“Automation is becoming key as people are doing more concentrated efforts and more expansive efforts offshore in deepwater and harder to get to places, and [using] different collaboration technologies that automation can provide,” says Tracey Haslam, vice president of strategic markets at Honeywell.

Global demand for hydrocarbon energy continues to drive production, especially in offshore reservoirs. The jump in hydrocarbon production placed big demands on automation systems. To increase the production to meet the growing global demand, oil and gas producers are closely looking at how these technologies and solutions work and can be put to use. That is where the use of machines, control systems and information technologies to optimize productivity in the production of goods and delivery of services – automation – comes into play.

When the producers pull oil out of the ground, they get oil, gas, water and dirt.

The way those elements flow; it is not an easy ride, which means slugs clogging up pipelines. Those slugs could trigger an alarm that could shut that facility down. That is where an automation system works its magic. The system can look at the profile and do some extrapolation of the liquids coming through. Using flow meters and putting advanced automation controls on the flow that alert when there is a slug coming, the system should adjust the range of out-set points or tighten the valve. If the system did not do that in real-time, then that slug could shut down the process.

The conventional wisdom says: if the system shuts down it will take at least eight hours to get it cleared and back up. That is lost production and lost profitability.

“Automation has become more than making sure the thing turns on and off at the same time,” Haslam said. “It now provides essential business information; saying things like ‘if I had everything working like this, here is what my flow rate should be.’ When you have automation that puts itself up into business information that has a cohesive look and feel, then you don’t care which platform or which source it comes from. You start to get into optimization areas. It is not so much about turning things on and off, it is about how you make business decisions on how you can catch incremental profit as you are producing oil.”

Quick on the draw

“You can get to a point where you say: now I have my production running smoothly; it is all good; my set points are fine. And someone else has a slug and shuts down because they were not using automation,” Haslam says. “If they shut down and they are feeding into the same pipeline as me, if I have automation watching that [situation] and it can automatically ramp up the amount I am putting into that pipeline, because the other guy has gone away. That means I can get paid more for my allocation, because there was an opportunity to do so. If you don’t have automation, then you can’t take advantage of all opportunities.”

“If you are getting between three and six percent increase in production, it is a huge financial benefit in terms of the cost compared to deploying a controller,” says David Bleackley, senior director global accounts at AspenTech.

In addition to advanced process control, Bleackley says they have been working with BP on production optimizers, based on steady state process simulation models. “We have done a number of these with BP where they have been talking about a seven percent increase in production on their assets, which is a couple thousand barrels per day, which rapidly scales up to millions of dollars a year in increased production. The benefits are considerable and the cost to deploy these solutions is considerably lower than sinking a new well.”

That kind of thinking also falls in line with Ormen Lange operations. It all comes down to taking advantage of any and all opportunities the technology will allow.

Through a series of process optimization procedures, Norske Shell was able to boost production of condensates, which led to hiked returns.

Norske Shell paid $4.3 million for the optimization project up to 2010. That amount was recouped quickly through more rapid start-up and increased uptime. The project went so well, the gas producer extended it for another two years.

“We have also introduced several improvements to the process. For instance, condensate production has increased. Condensate is a more valuable product than gas, so this helps increase revenues. The process is now optimized to produce the highest proportion of condensate possible,” says Arne Røsdal, Norske Shell’s operations support supervisor of Ormen Lange.

Along with faster commissioning and start-up, the project also increased uptime by four to five days per year, which represented an increase in revenues. The simple math shows cash flow increases the more uptime you have. You are potentially pulling in $23 million in a day. Increasing uptime by five days brings in an additional $115 million a year and that is by only producing 40MMcm/d. The field production capacity is actually 70MMcm/d of gas.

“In addition, there were energy savings of more than 3MW. Significant energy savings came about by optimizing control of the export compressor by reducing the cooler temperature, which made more power available to increase the export rate.

“All energy efficiency improvements are of interest. Electricity is a large part of the running costs for the plant and Ormen Lange also pays for the CO2 emissions. In addition, we have to work within the maximum capacity of the electrical plant. If 1MW is saved, the freed-up capacity can be used somewhere else, for instance to increase the export rate, which will boost revenues,” Røsdal says.

Offshore trending up

In the Annual Energy Outlook AEO2013 from the US Energy Information Administration, offshore crude oil production trends upward over time, fluctuating between 1.4MMb/d and 1.8MMb/d, as the pace of development activity quickens and new large development projects, predominantly in the deepwater and ultradeepwater portions of the Gulf of Mexico, come into production.

To get to that higher pace of development, producers will have to pursuer greater degrees of integration, which is rapidly becoming a big market demand.

“What we used to see was [that] people would put a bare bones system on the platform to do the separation control,” Haslam says. “Then they would have a very basic shutdown system. Now they want the interplay between that. They want a higher level of shut down integration. Not just with topside control, but with subsea control. Integration with subsea control, topside control, separation, and shutdown systems, and we start to get into the present environment that includes security, which includes physical perimeter security and cyber security.”

Integration would also include collaboration, she says. “You are not going to staff the offshore facility like you used to. You are going to keep [the platform] at the minimum required personnel to operate it and you will use experts from across the world to optimize it.”

At the end of the day, how much does an automation system help add to the bottom line?

The numbers vary, Haslam says, but it ends up being a positive influence. “We looked at where automation would make an impact and just from tightening up the controls and instead of operating in manual – and there are quite a few systems that still run in manual – you can gain 2-3%. The real money comes when you have an integrated infrastructure and platform and you are able to make optimization decisions. You can start to make those decisions where you can back off your operating boundaries when you need to, so you don’t have to shut down the operations for three days and you lose three days of production.

“So, instead you can just back it off for three hours and call it back up again when you get out of a scenario. So the impact of those incidents [is that] you can very quickly quantify it by looking at the lost profit opportunities. How many times were they down last year, and what was the root cause of those issues? You can often find automation is the potential cure for those root causes.”

If a producer uses integrated automation technology available today, Haslam says they can expect 3-9% growth on some mature fields.

Like most things dealing with automation upstream, it is new so it is difficult to come up with hard and fast numbers.

“Some companies have done an internal project review and they have demonstrated the savings of 15-20% of the whole automation integration project. That is on engineering hours saved; the predesign load by the EPC as well as the bid and evaluation process, and the detailed design around the one company,” Mao says.

“Coming to the integration part or the operator effectiveness, that is relatively new and there has not been enough run time.”

Compliance and regulations

When you integrate safety and compliance into the offshore scenario, a more automated environment ends up saving man-hours. Since the Macondo blowout and spill in the Gulf of Mexico, offshore operators there are working with a new and increased set of safety rules and regulations,including the Workplace Safety Rule and the Drilling Safety Rule.

In October 2010, the US Bureau of Ocean Energy Management, Regulation & Enforcement (BOEMRE) – now the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety & Environmental Enforcement (BSEE) – launched the Workplace Safety Rule, which mandates oil and gas operators develop and maintain a safety and environmental management system (SEMS), which is a comprehensive management program for identifying, addressing and managing operational safety hazards and impacts. The Workplace Safety Rule covers all offshore oil and gas operations in US waters and makes mandatory the previously voluntary practices in the American Petroleum Institute’s Recommended Practice 75 (RP 75). The Workplace Safety Rule became an auditable regulation in November 2011.

In addition to the Workplace Safety Rule, the US Department of Interior established the Drilling Safety Rule, which became effective immediately in 2010. The regulation prescribes proper cementing and casing practices, and the appropriate use of drilling fluids to maintain wellbore integrity. The regulation also strengthens oversight of mechanisms designed to shut off the flow of oil and gas, primarily the blowout preventer (BOP) and its components, including remotely operated vehicles, shear rams and pipe rams.

Operators must also secure independent and expert reviews of their well design, construction, and flow intervention mechanisms.

Now within the automation environment, operators have to have the policies and procedures documented and they must be accessible from the control system.

“Whatever procedure you have from shutdown to start up, those policies and procedures are only a mouse click away so the operator can review those,” Oyen says. “Everything gets documented within the control system; if those procedures get updated it propagates throughout the system. If you are making a change because you added additional production, and you need to make set point changes, or alarm changes, that gets documented throughout the system.

“Your operator has an object, when he logs onto the system and when he logs off, it tracks his hours, how long he has been on. When he is on the training simulator linked into the control system, how many simulator hours he has. It clicks for his manager to sign off that the operator has been in offshore safety school and refresher classes. All of this makes an audit trail, so you can quickly show your regulator, or your auditor, that changes made in the system get propagated throughout the system and they get documented.”

That is where technology can integrate with various safety and compliance cultures: through automation. OE Review

Gregory Hale is the editor and founder of Industrial Safety and Security Source (ISSSource.com) and is the former editor of the manufacturing automation magazine, InTech. He is also the co-author of the book Automation Made Easy. Everything you wanted to know about automation – and need to ask.

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