The recovery factor
The recovery factor - enhanced oil recovery
Every single day at its Prudhoe Bay oilﬁeld in Alaska, BP produces gas, along with crude oil, lots of gas. It refrigerates it to around 40°C below freezing and re-injects into the reservoir almost as much gas as is used across the whole of the UK every day.
The process of refrigerating the gas enables BP to extract liquid hydrocarbons that can be blended into the crude oil and sold, but it also allows the company to increase oil recovery from Prudhoe.
BP is leading the way in driving up the amount of oil that can be recovered from the ﬁelds it operates. The groundbreaking ideas associated with this practice, known as enhanced oil recovery (EOR), have got the attention of the oil industry world-wide. So what’s involved in EOR?
What is a reservoir?To a non-specialist, a ‘reservoir’ might conjure images of a large volume of liquid sloshing around in one place. But it is, in fact, rock with millions of tiny holes – or pores – that ﬁll with oil and gas. These pores act as storage spaces. The type of rock in the reservoir will determine the rock’s porosity and a reservoir can look like anything from a chunk of airport runway, in other words, extremely compacted, with microscopic pores, to coarse sandstone, with pores that are visible to the naked eye. This variation is caused by the grain sizes within the rock and by the depth at which the reservoir rock is buried. The deeper the rock, the higher the temperature and pressure, causing the rock to compact, and cement to form between the grains.
The nature of the reservoir’s pores, or, more precisely, how connected they are – its permeability – is important when it comes to removing the hydrocarbons from the subsurface. The size of the pores determines the rock’s ability to store oil and gas, while the permeability determines the rate at which oil and gas will ﬂow from the rock into a wellbore.
Maintaining pressureIn BP, the effort to enhance oil recovery is led by its Pushing Reservoir Limits™ (PRL) team, one of a number of technology ﬂagship programmes in BP. PRL research and development manager Raymond Choo says: “In a typical reservoir, around 10% of the oil can be retrieved by simply drilling a hole, sticking a pipe into the reservoir and letting the natural pressure force oil up the well to the surface. As the oil is produced, so the pressure falls in the reservoir until it can no longer support a column of oil to the surface. At this point, the well stops ﬂowing.
“To get more oil out, we have to maintain that pressure, usually by injecting water – a ‘waterﬂood’ – or gas. In either case, the injected ﬂuid ﬂows through the pores in the rock, forcing the oil ahead of it. But the injected ﬂuid follows the easiest path, so some pores are missed. Another factor is that some of the oil remains stuck to the surface of the sand grains or trapped in the pores. Also, the injected ﬂuid doesn’t spread out fully from the injection well to access all the rock. These factors combined mean the worldwide average recovery from an oilﬁeld is around 35%.”
An oilﬁeld’s recovery factor is calculated by multiplying together four factors, known as ‘fractions’: pore scale displacement, sweep, drainage and cut-off (see panel on page 46 for an explanation on each of these).
Conventional EORBP's enhanced oil recovery efforts are focused on increasing the pore scale displacement and sweep factors, as these are the smallest of the four and, therefore, have the greatest room for improvement. For some time now, various technologies have been available to improve the efﬁciency of waterﬂooding – for instance, substances called surfactants are used to improve the pore scale displacement. Surfactants are similar to washing-up liquid; they help to remove oil from the surface of sand grains and reduce the amount that gets trapped in the pores. But they are expensive and, since they are consumed by the rock, you have to inject a lot of them. Another method is to use polymers to thicken the water, which can help to increase the recovery.
Gas injection – the method used at the Prudhoe Bay oilﬁeld in Alaska since 1986, is another option. By processing natural gas to modify its characteristics, BP is able to recover a lot more oil than would otherwise be possible. Some of this gas is used to create what is called miscible gas. This gas is very good at pore scale displacement and typically extracts up to 95% of the oil from the rock it sweeps. Prudhoe Bay is the world’s largest hydrocarbon miscible gas project.
Similar programmes are in operation in BP-operated ﬁelds in the North Sea. EOR at Norway’s Ula ﬁeld began in 1999 and is estimated to account for around 70% of the current oil production there. At the Magnus ﬁeld, EOR started in 2001 and is estimated to account for around 30% of current production.
PRL and the new technologiesBP's leading technologies have come about as a result of a deliberate choice by BP’s PRL team. Rather than simply continue the industry’s progress in incremental development of existing technologies, the team chose to focus on revolutionary low-cost EOR techniques.
Low salinity water (LoSal® EOR)Seawater is commonly used in traditional waterﬂooding techniques, injecting it into reservoirs to maintain pressure. The PRL team saw evidence that low salinity water containing almost as little salt as drinking water can release oil that would otherwise remain bound to the sand grains. The team carried out many inhouse laboratory tests using real reservoir rocks, followed by further tests in rock around actual wells, before ﬁnally conducting a full-blown, multi-million-dollar ﬁeld trial at the Endicott ﬁeld in Alaska. Here, the team injected low salinity water into one well and monitored the resulting oil production from another.
Todd Buikema, manager of the PRL deployment team, says: “The development of LoSal EOR technology has taken 20 years, with BP publishing numerous papers reporting on progress as it pioneered the way forward. All this effort has been rewarded with the world’s ﬁrst sanctioned offshore low salinity project at Clair Ridge in the UK. The Clair Ridge platforms will be equipped with desalination equipment to reduce the salinity of the 145,000 barrels per day of injected water that are needed.
“This should deliver approximately 42 million barrels more oil than a ﬂood with conventional seawater would,” says Buikema. “This translates to around $3 per incremental barrel, which is pretty impressive in the world of EOR.”
The technology is so effective that BP has decided that low salinity waterﬂooding should be the default for all future sandstone waterﬂoods. Other low salinity deployment projects are at various stages of development, including plans to include LoSal EOR in the second phase of the US Gulf of Mexico’s Mad Dog ﬁeld.
Improving sweep with Bright Water™ particlesThe properties of sandstone rock vary a lot, depending on the size and mix of the sand grains it's made from and whether other features are present. Sandstones tend to form as a sequence of layers, some of which may have low permeability and some high. Often, there are a few layers with much higher permeability than the rest of the ﬁeld. Fluids ﬂow most easily through the more permeable layers, so, this is where water from the injection well will naturally go and rapidly push out the oil.
But, these more permeable layers quickly ﬁll with water, which then starts to be expelled along with the oil. Once this happens, any more water entering this layer is wasted as there is little oil left to push through, so the water cycles through, down the injection well, rushing through the water-ﬁlled layer and up the production well. Because these layers tend to 'steal' a disproportionate amount of the injected water, they are referred to as 'thief zones'.
To combat this, BP had the idea of a particle that could block off these zones deep in the reservoir between the injection well and the production well and co-developed technology known as Bright Water particles. Paul Denyer, Bright Water particle deployment manager, explains: “The particle is a long-chain molecule held in a tightly-bound ball – rather like a ball of wool. These balls are so small that they can be added to the injection water and pass unimpeded through the reservoir rock. When cold seawater is injected, it is warmed up in the thief zone by the hotter, unswept rock above and below it. This breaks some of the links in the Bright Water particle and the tightly-bound ball pops open into something around 10 times bigger.
“These bigger molecules struggle to get through or become completely stuck in the tighter gaps between the sand grains and the water ﬂow is dramatically reduced. The result is that the injected water is forced to take a new path and sweep new rock, which then increases the oil recovery from the ﬁeld.”
BP has demonstrated the performance of the Bright Water particle in ﬁelds in Alaska and its Argentinian joint venture, Pan American Energy, and elsewhere. Bright Water particle treatments performed so far by BP have provided additional hydrocarbon resources estimated to be more than 20 million barrels above what might otherwise have been recovered without treatment, and at an attractive EOR cost.
Winning teamsThe PRL group that came up with these innovative solutions is organised into four teams covering research and development, laboratory, deployment, and computation rock physics – developing new technologies for reservoir characterization and performance prediction that are important to optimising oil recovery. The teams are centralised in BP’s two main upstream technology centres in Sunbury-on-Thames, UK, and Houston, US.
The world-class laboratories they use contain equipment such as whole-body medical CT scanners for seeing inside the rock samples. With a successful track record established, the PRL teams are growing to cope with the new technologies and to ensure that BP extracts the maximum beneﬁt from their deployment.
PRL technology innovation leader Andrew Cockin says: “BP has been a leader in EOR for a long time. We operate the world’s largest hydrocarbon miscible gas project, as well as several other signiﬁcant projects, such as at Magnus and Ula. We have created novel, highly-cost-effective EOR technologies and have more EOR technologies under development to revolutionise EOR further and increase the recovery factor.”
EOR is starting to show that it has the potential to make a real contribution to resource replacement. Cockin says: “Historically, oil companies moved on to new ﬁelds when conventional oil production fell to uneconomic levels. As the hunt for new giant oilﬁelds gets harder, so the desire to recover more from existing ﬁelds increases. When national oil companies are considering who to partner with, the ability to recover more oil is a quality they value more and more. “This is a good time to be working in enhanced oil recovery and a valuable area for BP to be a world leader.”