What lies beneath

By Jeremy Webb One of the world’s most unusual oil fields sits in the Norwegian Sea. Were you to make the 200-kilometre journey from the nearest city of Trondheim, you’d see no sign of activity, no oil platforms or processing plants, no support vessels – not even any other people. Yet 300 metres below the surface, nine wells are extracting oil and gas from a reserve almost four kilometres beneath the seafloor. The wells are controlled remotely via fibre optic cable. The oil, gas and water they produce is transported to the Kristin platform, 40 kilometres away, for processing and further export. This is the Tyrihans oil and gas field, operated by the global energy company Statoil, and it is a model of how much of the world’s offshore fuels will be extracted in future. “It’s inevitable that we’ll see a lot more of this kind of oil production,” says Babs Oyeneyin, a chemical engineer at Robert Gordon University in Aberdeen. As the world’s oil reserves become depleted, energy companies are forced to look further afield for new supplies and find different ways to mine fields that were previously thought to be too costly to exploit. Tyrihans falls into the second category. Discovered in the early 1980s, the field contains about 186 million barrels of oil and 43 million cubic metres of gas, all of which sit in a deep band of rock that is only 100 metres thick. The water here is too deep for divers to reach, which adds significantly to the complexity of extraction. When Statoil ran the numbers, they didn’t add up. Conventional methods just wouldn’t pay off. So the company chose another approach. Forty kilometres north of Tyrihans is Statoil’s Kristin field, which it decided to use to control Tyrihans. “This reuses the infrastructure already in place and extends its lifespan,” says Snorre Grande, project manager for Tyrihans. The result was that the cost of extracting the gas and oil dropped dramatically, making Tyrihans a potentially profitable prospect after all. Tyrihans would not need its own platform on the surface, but would require an oil and gas production facility on the seafloor. The relative position of the wells is determined by five ‘templates’ – giant metal frames that are lowered to the seafloor (pictured, right). The wells are then drilled through holes in the templates and capped with valves. These connect to a further set of pipes, sensors and valves that mix the flow into and out of the wells. All the equipment is controlled and powered by a 45-kilometre umbilical running back to Kristin. In the past, one of the problems with remotely operated wells was that they were never able to extract as much oil from a given field as a platform. That’s because platforms have greater control over how the oil is extracted. For example, they can pump water into a reservoir to increase the pressure inside it. That just hadn’t been possible for remotely operated wells – until the advent of Tyrihans. Here, Statoil has created new technology to allow conventional platform injection pumps to be moved down to the seabed. Alongside the nine production wells these pumps – the largest of their type – can force up to 14,000 cubic metres of seawater a day into the reservoir via an injection well. Statoil also reinjects natural gas into the reservoir through two additional wells. This gives close control over the gas and fluid pressures inside the reservoir. Several of the well bores have branches that extend into different parts of the reservoir, saving the cost of drilling extra wells. These ‘smart wells’ have valves that can be opened and closed remotely, and are fitted with pressure and flow sensors. Statoil can then assess conditions in different parts of the reservoir and choose the best places for extraction. According to Statoil, these innovations should increase the field’s yield by at least 19 million barrels over its lifetime. They will go a long way to making up the potential shortfall that arises from using subsea wells rather than a platform. Perhaps the biggest challenge that Statoil faced was to build a pipeline capable of carrying oil 43 kilometres along the seafloor to Kristin. The oil gushes from the wells at a temperature of about 30°C, substantially warmer than the surrounding sea, which is a chilly 4°C. If you stop the flow for any reason, however, the pipe cools, which causes trouble when you want to restart the flow. The falling temperature, combined with the increased pressure on the seafloor, causes water in the oil to freeze. As ice forms, it traps gases, including hydrocarbons, forming what chemists call a gas hydrate. Hydrate crystals are the bane of the oil industry. They damage valves and sensors, and block pipelines, shutting down operations until the plug can be removed. In order to prevent gas hydrates from forming, all 43 kilometres of the Tyrihans pipeline are electrically heated, making it the longest heated oil and gas flowline in the world. When the oil flow stops for any reason, the crew at Kristin switches on the heater before restarting the flow. This is no minor task. In order to reach operating temperature, it can take 36 hours and 10 megawatts of power from the Kristin platform: that’s enough to keep a small town running. Tyrihans must also be ultra-reliable. Machinery on a platform may be easy to maintain and replace, but equipment sitting in water so deep that it can be reached only by remotely operated subs must be more dependable. As a result, the subsea systems have lots of built-in redundancy. Most of the equipment is housed in relatively small modules that can be replaced by a ship equipped with a remote sub and modest lifting gear. Such ships are easier and cheaper to use than the heavy-lifting barges that a lot of underwater engineering requires. Grande says the design of the subsea systems is an important factor: “There’s been almost no downtime. The reliability is very good.” After drilling the wells, Statoil tested the subsea equipment and plumbing for leaks. Finding none, it began to produce oil and gas. “We did it on budget, on time and with minimal environmental impact,” says Vidar Skjerdingstad, Tyrihans project control manager. Since July 2009,
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