Coiled Tubing, Nanotech to lower well-intervention costs as operators focus on life-extensions
The increasing use of Coiled Tubing and nanotechnology is set to lower future well-intervention costs as operators implement life-extensions strategies in response to low oil prices and regulatory pressures, Peter Koopmans, Quality Assurance Advisor at Hess, said.
For offshore Gulf of Mexico fields there is increased emphasis on making technical changes to wells as early as possible, ideally at the well design stage, including the installation of Enhanced Oil Recovery capabilities on new platforms.
“Regulators and operators are now asking upfront: is your well designed not just from a drilling and execution point of view but is it designed to be worked over relatively easily if the reservoir proved more valid than initially anticipated,” Koopmans told Upstream Intelligence.
Operators need an intervention strategy, typically over 25 years, which allows them to make changes to infrastructure several years into the life of the platform once production starts petering off for technical reasons, he said.
The additional costs are relatively low in comparison with the overall spend on a new platform.
Spending on new deep water platforms can cost between $140 million and $180 million and an additional investment of $2 million at well-design stage could buy a platform years of additional life, Koopmans said.
Coiled Tubing, the use of a very long metal pipe in operations similar to wire-lining, can provide significant cost savings in later stages of production.
“If you take a situation where two years into the life of a well you need to bring on a gas tube, there is a huge difference between having to hire a rig at $1 million a day or a barge with coil tubing at $265,000 a day to get that well restored to full operation volumes. This is something you would not have been able to do before.”
If the production level of a well starts to deteriorate because of problems caused by sand or scale, in the past cleaning it out and restoring it to a high level of integrity would have involved using a full rig with a drill pipe to drill out the obstacles.
But tubing technology has reached a new level and can be used at depths of 30,000 feet – a major advantage over wirelining in open waters - and withstand a higher pressure, making it the preferred technology for cleaning and restoring wells.
Another new approach being adopted is the use of nanotechnology within the equipment used in offshore operations, although this technology is still several years away from industry-wide application.
Nanotechnology can, for instance, provide a layer on the surface of the pipe which makes up only about 2% to 3% of the wall thickness but creates a layer of sheathing that gives the pipe anti-corrosive properties and makes it far more resistant to the high pressures which are typical of deep water production environments. This makes it possible to reach zones that would have been out of reach using conventional tools.
At present only a handful of companies provide the technology and it will likely take until 2018 or 2019 for manufacturing capacity to catch up with the needs of the offshore oil industry.
A more established technique for extending well life is Enhanced Oil Recovery and here the industry is focusing on which gas or liquid to use next.
The most traditional, water-flooding, is now widely in use and is estimated to be able to displace about 20% more oil out of reservoir than primary and secondary extraction.
Though relatively cheap – BP estimates that water-flooding increases overall cost by only about $3 a barrel – it still leaves about 50% of the reserves untapped. Using gas injections can displace at least another 5% of reserves, depending on the type of gas used.
“The type of technology used for EOR depends very much on the nature of the reservoir,” said Marco de Weegh, Team Leader, Well Control and Design at Shell.
While water-flooding is the easiest approach for reservoirs which are mostly horizontal, injecting gas lends itself to reservoirs which have a tilt in their structure.
Linde Group’s director of Enhanced Oil Recovery Business Development Kevin Watts said that nitrogen injection used by Linde lends itself particularly to reservoirs with a dip. The gas is super-cooled on shore and then transported by underwater pipelines to the platforms.
The technology is more cost effective at shorter distances from the shore and for platforms up to a certain depth but is relatively straight forward.
In contrast to water, nitrogen can strip out much of the lighter ends of the oil.
“The nitrogen will preferentially move the C2 to C6 content of the oil and will put it into a solution in the nitrogen,” Watts said.
“As the nitrogen moves through the reservoir it keeps stripping out these lighter ends of the oil. You then have to separate the liquid hydrocarbons from the gases produced with nitrogen,” he said.
Other gases used for injecting old fields include methane and CO2. The latter is widely used in onshore wells when it is readily available but for the time being is still costly to transport from onshore industrial users to offshore platforms.
The US government is looking to promote the use of CO2 for EOR but for widespread offshore use this will most likely require some form of subsidy.
The holy grail of extraction is to be able to pump 100% of the oil from the field and while this may never be achieved, current technologies are expanding the bounds of possibility for oil engineers.
By Vanya Dragomanovich