With oil prices remaining low and climate change agreements putting pressure on companies to seek out low-carbon alternatives, there is less investment going into finding new oil fields. Instead there is an increasing shift towards enhanced oil recovery – maximising production from existing assets by injecting heat or chemicals.
Companies big and small are working with academics to perfect enhanced oil recovery (EOR) techniques, as well as develop innovative, cost-saving technology to increase oil production.
This is something that BP has been doing with its BP Institute, which is part of the University of Cambridge. Although the building and original faculty were supported by a BP endowment 15 years ago, the company makes it clear that the researchers are free to choose their topics of study. So their research covers a broad spectrum, from healthcare to car engines, but is focused around studying dynamic, multiphase, fluid flow.
The research that the institute has done in the field of oil and gas has already helped to improve BP’s scientific understanding and practical application of enhanced oil recovery in a big way.
Waterflooding is used as a cost-effective way to increase oil production, so the team developed experiments to model what impacts the flow of water injected into reservoirs. The amount of oil recovered from the process can vary widely depending on the geology.
Professor Andy Woods, head of the institute, says: “On average, you only recover 35-40% of oil from reservoirs in the North Sea. A lot of that is associated with the difficulty of trying to sweep out the oil. These experiments are a very simple way of understanding those mechanisms.”
One such experiment looks at what causes an increase or decrease in the amount of oil that can be recovered from turbulent fluvial systems: a series of sinuous channels of oil that have formed over geological time.
Simplifying that complex geology in the lab, researchers have created a model out of a straight, 0.5mm thick, diamond-shaped cross-section that represents an oil channel, encased in perspex. The model is tilted at an angle of 45°, as if tectonic plates had shifted and tilted, to see the effects of gravity across it.
Water is used to represent oil and researchers pump in glycerol dyed with ink, which represents the water that would be injected into the reservoir.
Woods says: “The flow is being pumped in and wants to go along the middle but because the ‘water’ we are pumping in is denser than the ‘oil’ it wants to sink. There is a competition between going along the middle of the channel and going along the bottom. That depends on the resistance at the bottom compared to the middle and how fast it is travelling.”
To recover a lot of oil you must pump in water at a high rate, but Woods says that this can mean bypassing oil at the start of the channel. One thing operators do to mitigate this problem is to add a polymer to thicken the water. While operators were aware that this can recover more oil in some reservoirs, little was known about exactly why it worked or how it could be improved upon.
Woods and his team of researchers have been able to learn more about this effect by changing the viscosity of the glycerol fluid they pump into the model to witness how the flow changes, and what pump rate achieves the best oil recovery.
What the team found was that the oil placement in the channels shifted over time, from the bottom of the channel to the top. This has helped BP to understand where the “target” oil will move throughout the EOR process. Woods says: “Real systems are complex so building up these blocks gives us a lot of insight into how effective a polymer might be.”
With a thicker liquid injected into the channels the team found that, while water reached the end of the channel quickly (symbolising water breaking through to the production well), much of it was still gathering at the start of the channel and working well to push the remaining oil out. “So you might think it has short-circuited the system but it is actually still having a big impact,” explains Woods.
David Eyton, group head of technology at BP, says that the company has been “very focused” on low-cost EOR, especially for the past 10 years in “light oil” reservoirs, many of which are “waterborne”. Adding in chemicals or removing salt from the water to increase reservoir production is considered to be effective and “comparatively low cost”.
BP has the first commercial-scale application of low-salinity, or LoSal, waterflooding in the North Sea, which Eyton says for an investment of just over $100 million will get a return of an extra 40 million barrels equivalent of oil. They are now looking at a combination of LoSal EOR with polymers so that “when the water turns up it gets more oil out”.
Eyton stresses that to justify investments of $1 billion over the life of a field when adding in chemicals to the water it is really important to know that they are doing their job. However, creating accurate models of the complicated systems that exist in reservoirs is “near impossible”. Instead companies must rely on approximations and create rough computer models.
“Before we did these experiments at the BP Institute it was very difficult to know what was going to happen,” says Eyton. “There are real-world applications of this although it may seem like we are just putting dye into a tank.”
In a bid to push forward innovative ways to cut costs and improve efficiency in the industry, the Oil & Gas Innovation Centre in Aberdeen has recently released £85,000 to support three companies working with Scottish universities to develop their technology. The centre has provided more than £1 million of support for technology development to companies and universities in the past 18 months.
Cavitas, one of the three companies to receive the latest funding, will be working with the University of Strathclyde on its thermal EOR technology. The thermal Heavy Oil Recovery (Thor) system is a downhole device that uses a rotor within a housing to heat fluid or steam inside the wellbore of injection wells and can be used as a bypass fluid heater.
Steve Johnstone, managing director of Cavitas, says: “If you inject heat into heavy oil fields the production rates can increase quite dramatically. What has generally ruled it out from an offshore perspective until now is the cost and the ability to generate heat or steam offshore.”
The technology is based on the rotation of the rotor within a housing and it could improve the economic feasibility of heavy oil and enhanced oil recovery. Oil and Gas UK estimates there are 9 billion barrels of known reserves of heavy oil in the UK Continental Shelf which, at the moment, are not economically viable to produce.
The University of Strathclyde will model fluid dynamics to allow Cavitas to develop its design and to build a prototype of the mechanical heating device.
Johnstone says Thor improves upon previous thermal EOR methods as it has flexible power options and does not suffer from the same volume of heat losses.
Thor will be designed small enough, around 18-23cm, for installation within wells and will be powered via downhole devices such as electrical submersibles or hydraulic submersible pumps. Johnstone stresses that, with just one moving part, it is very robust but if it were to break down it would be small enough that it would not plug the well and stop production.
Cavitas has built and tested proof-of-concept devices and is using the data gained to feed into research being carried out by the University of Strathclyde.
Initial geological modelling using actual heavy oil reservoir data provided by a partner company has indicated that relatively small temperature increases yield big results.
Injecting fluid at 50°C with “quite a small injection rate” will see an additional 2-9% of oil recovered. “If you’re talking about 1 billion barrels worth and you add an extra 10% that’s another 100 million barrels of oil,” explains Johnstone. “Over 30 years and even at the low oil price it’s still a reasonable chunk of change.”
Once a working prototype has been built, the next challenge will be finding someone to allow us to test it, says Johnstone. The company has had initial talks regarding testing its device with a central Eastern European land-based operator.
Johnstone says: “Going from land-based to offshore will obviously be a jump in itself but from my experience in the industry oil companies like to know it has been used by somebody else before.”
Cavitas is also in “fairly advanced” discussions with a major global equipment and service company which could provide technical expertise and potentially co-market the device.
“There needs to be a fundamental change on how the basin operates,” says Johnstone. “But I think that will be a slow change because of the cautiousness of the operators at the top of the tree.”
Johnstone has been on the receiving end of this cautiousness, having been rebutted by major oil operators when seeking technical support and geological data to help develop the firm’s device.
“One of my biggest frustrations is that the larger companies are very good at preaching innovation and that they are open for business but the reality is somewhat different,” he says.
It is understandable that in tough financial times companies will be risk-averse. But Johnstone says that if all that is being asked for is technical assistance then surely they should be open to collaboration on potentially “game changing” technologies. The question is, are major operators doing enough to create a culture where their employees feel able to take a punt on new but promising technology?
Did you know? Reservoir surveillance could boost yields
Silicon MicroGravity (SMG), a spin-out company from Cambridge University, has developed a high-performance microelectromechanical systems (MEMS) accelerometer to improve oilfield reservoir surveillance.
Described as having “breakthrough sensitivities” when compared to alternative MEMS accelerometers, it enables high-resolution gravity measurements of approximately one billionth of the earth’s gravity, around 1000 times more sensitive than the accelerometers found in a mobile phone.
Current mechanical sensing systems are fragile and constrained to large-diameter vertical boreholes. However, SMG’s technology, created with BP, is small and robust enough to be sent deep into boreholes to identify oil from water.
Once the position of water is established and tracked, reservoir engineers can mitigate the potentially damaging results of water reaching a production well. SMG estimates that the technology could improve yields on conventional reservoirs by up to 2%.
SMG was launched with initial funding of $3 million from venture capitalists together with grants from the government and the IMechE Stephenson Fund.