with Havard Devold, Group Vice President Oil & Gas Upstream Process Automation Division, ABB Norway
How would you begin by mentioning how you see Norway’s role within ABB’s global portfolio?
Norway is clearly one of the important global centers of excellence within ABB’s global oil & gas division. Norway and Italy as well as some smaller centers in the US, UK and Singapore comprise a network of key operational hubs for the company and its technological development. Within this network, Norway has played an important historic role in the development of our technologies. Our presence in Norway dates back to the very start of the industry here. Indeed, ABB started growing its position in Norway from the 1970s and early 1980s. At that time, ABB identified an extremely positive environment for the adoption of new technology and support for the service sector.
The Norwegian E&P players and Statoil, in particular, were on a mission to develop an advanced supplier industry in Norway. The entire regime was designed to favor the development of the supplier industry. The positive environment was not just about Norwegian suppliers being favored in tenders; the system was set up to allow for ‘active mentorship’ of the supplier industry. Part of this mentorship involved a proactive approach to incorporating new technologies, taking risks and working through the failures. Unlike many parts of the rest of the world, the climate created in Norway was not risk-averse or hostile to the adoption of new technologies. Even today, in the rest of the world you will still often find requirements for a five-year proven track record before a company will adopt a given technology. Companies in other jurisdictions have been highly focused on project execution rather than innovation. This is the basis of their conservatism. The motto in Norway has been completely different and their proactive approach to technology is the main reason that we have a strong industry here.
ABB’s first major contract opportunity came in the 1980s. Our fist significant project was to install the control systems for Statoil’s Gullfaks platform. Working with Statoil, we had the opportunity to develop our latest control system into a fully distributed control system architecture. It took a further 20 years for these control systems to reach full maturity in other markets. We also worked on the safety systems for the Heimdal field for Elf (now Total). We were installing systems, which had never been done before. Through this partnership we were able to develop fully programmable safety systems.
In Norway, ABB has worked on installation of some of the world’s first electrification systems for the oil and gas industry, when Statoil decided that they wanted large drives on the Troll , rather than use conventional gas turbine technology. Later came the first opportunity to prototype a High Voltage DC power-from-shore solution on the same field. BP Norge then decided to implement the same technology on Valhall. Then, we could do AC power from shore on Staoil/Gaz de France Gjøa, ENI on Goliat and Total E&P Norge will be doing the same for Martin Linge.
Linking platforms to the grid is by no means the obvious solution in Norway. There are numerous discussions on many different levels of the public and private sector about the comparative value of either exporting electricity for base power consumption in Europe or consuming the electricity in Norway for industrial use. This equation is complex. Nonetheless, the operators have remained clear in their intentions. The stability of these operator decisions has allowed us to commit to developing some of the world’s leading technologies for the oil and gas industry.
One of the core concepts driving forward the search for new technology is Statoil’s ‘subsea factory’. Statoil’s idea is to place unmanned subsea production facilities in remote areas and even beneath Arctic ice; however, these facilities would still need access to power. ABB’s task is to work out ways to transmit this power over very long distances from shore. In Norway, we have prototyped power from shore and installed some of the very first electrification systems, which are now becoming the norm for the industry worldwide. Many people working in the industry worldwide call Norway the North Sea laboratory, given the number of technologies developed here.
Is this climate of active mentorship changing with the arrival of newcomers to the NCS?
The mentorship has been reduced as the industry matured and e.g. EU procurement rules made the business more international. But the technologu challenge still remains.
The minor companies do not have the same approach to technology. They have their own role in developing resources, which require a more lean and mean approach. As a consequence, their approach to development is much more similar to other places in the world from Southeast Asia to Africa and they take fewer risks in trialing out new technologies. Unlike Statoil and some of the majors they are more short-term focused, thinking more about returning equity to shareholders than long term value creation. Their role is important for the NCS as it allows value creation with a limited use of resources, whilst the major oil companies can devote resources and time to expensive development programs and operations in the Barents Sea.
What do you see as the main contributions Norway will make to the international market in terms of innovation in the coming years?
Subsea technology is going to remain a major focus both in Norway and in other parts of the world. However, the technology about which I am particularly excited is the area of integrated operations as well as its various other names: digital operations, smart fields, the i-field etc. My hope is that the technology in this area will progress from addressing individual problems in the course of production to becoming the way that the exploration and production of oil and gas is done. This means that instead of looking at this technology only in cases where the well or facility is under performing, integrated operations will be incorporated into the development of the well or entire facility as a standard. I see this being the case especially for the high North where ENI are already developing Goliat with a full-spectrum of digital oilfield technology from flow assurance to asset-management, production management to safety assessment and remote operations, etc.
The only time that such a complete spectrum of integrated operations was installed before was for Shell on Ormen Lange. ABB has recently signed a 10-year USD 270-million frame agreement for work on this field. These deals are an indication that the industry is already progressing from the situation of going to the dentist in order to fix a cavity, to maintaining proper oral hygiene, with flossing, brushing and all the rest. I believe that for some operators, integrated operations are already seen as an operational model, rather than an element of trouble-shooting.
If you want to perform a lean operation in the high North, away from populations, whilst maintaining a good understanding of the nature of the well with active monitoring and good contingency planning, integrated operations are the way forward. In the Arctic, you cannot go into the ice to replace a failing turbine or any other piece of heavy machinery. Smaller elements can be flown in with helicopter, but heavy equipment cannot be delivered in the winter. If there is a failure and resultant spill in this environment there is no known technology for recovering oil under the ice. The only way that safe operation of wells in the Arctic will be made possible is through integrated operations.
ABB has one of the largest groups providing integrated operations technologies for the Norwegian industry. There are numerous other large groups involved in specific fields. Last year Schlumberger bought SPT group just for access to flow assurance technology and there are others developing technologies for other areas. We are competing with the major systems supplier like Emerson and Honeywell. We are all seeking to address not just the major production issues but also the communications infrastructure. After the recent events in the Middle East people are concerned about sabotage and malicious acts. In our facilities we have the ability to orpvide operations support to Snøhvit, Draugen and several FPSOs. We use these facilities to assist companies. This means that the access to these facilities is as strict as for offshore facilities themselves. We are already capable of integrated operations and we will make further steps in the years ahead.
Around the world you can see this revolution coming. Some oil companies are dreaming of 24/365 control rooms dotted around the world so that part of the day a production facility is managed in India, part of the day in London, and part of the day in Houston. Then again, we still encounter a conservative industry. We tested integrated operations on the unconventional industry with the idea that you could sit in Houston and operate and monitor several drilling rigs in Bakken and do everything remotely from there. However, the industry is not quite ready for this step. Nonetheless, you can already talk about integrated operations with Petronas, Saudi Aramco, Kuwait Oil Company, BP, Shell and Rosneft. The fact that Rosneft is now going into the Arctic is forcing them to pick up on this technology.
How far ahead is Norway compared to the rest of the world and is the gap closing?
For me there is a split in the world between the early adopters and the more conservative industries. There is the classical auction-style model in certain markets where the cheapest wins the job. Oil companies, which want a quick return on investment and have low labor costs, will tend towards cheaper solutions. There are some technology elements, which will be adopted even in low-cost markets. There are more than 100 projects in the Middle East, where they are replacing gas turbines with electrical drives driven simply bu economics;. If you have an energy cost, which is less than USD 60-80 per megawatt hour then justifying converting to electrification is a simple economic calculation
The technology, which was pioneered in Norway is therefore finding its way into other markets. For example, the subsea developments in Norway are finding their way into the pre-salt developments in Brazil and West Africa. In some parts of the world, you cannot really take a conservative stance about flow assurance. Some people have commented that Angola almost seems designed to need the use of active lift, given the structure of the reservoirs there. In these reservoirs you need assisted flow, subsea compressors and multiphase metering. You cannot choose to adopt or not in many of these areas.
The world is past the era of easy oil and the next billion barrels of production will require more advanced technological approaches. You can see the use of technology in the current extension of major oilfields, for example, Ekofisk was found in 1969 and the first shipment was made in 1971. The plan back then was to shut in the facility in 2000 with a recovery factor of 17 percent. In 2000 they were looking at 53 percent recovery factor and a shut in date in 2028. Now we are talking about the possibility of keeping the field open past 2050. The value for ConocoPhilips and the Norwegian state is not something you can choose; it is simply a necessity.
When looking at total production, there are two lines dictating a well’s longevity: the production profile, which can be increased with better completions, stimulation and fracking technology etc. This will take the recovery factor up by 20-30 percent. However the other curve, which is often ignored, is the cost curve. You usually have a slightly rising cost curve with equipment being replaced, falling reliability and so on. It is the crossover point between these curves, where you need to close the field down. If you are able to make an operation leaner and more cost effective you can prolong the point at which the cost curve meets the production curve. This can be done by de-manning the field, switching from compressors to electrical drives, and using active diagnostics to understand how well equipment is functioning in order to maximize uptimes. ABB did a study for the NPD a few years ago about the value of these technologies and the amount of money that can be saved is staggering: tens of billions of dollars. This is why companies are focusing on these technologies. These small changes can generate huge volumes and now we are aiming at 70 percent recovery, which is the gold standard for the industry. This is why at ABB we call this the digital oilfield/ IOR.