Apart from finding new resources, how can the industry meet a growing demand for oil? BP Magazine discovers how increasing recovery from existing fields could play a vital role
BP’s Statistical Review of World Energy 2013 revealed that the world’s proved oil reserves at the end of 2012 reached 1,668.9 billion barrels, sufficient to meet 52.9 years of global production. But this is based on current recovery rates – even a small improvement in these rates would make a dramatic difference to the size of overall reserves. In 2011, then-president of the Society of Petroleum Engineers Alain Labastie wrote: “The current ultimate average recovery factor for oilfields, on a worldwide basis, is about 35%. This means that about two-thirds of the oil that has been discovered is left within the reservoir. We have under our feet, in well-known locations, enormous prospects for booking new reserves. Increasing the average ultimate recovery factor from 35% to 45% would bring about 1 trillion barrels of oil!” If you drill a well into a reservoir and rely on natural pressure to force the oil to the surface, you will typically recover around 10% of the available volume in place. Unless other forces act on the oil, pressure in the reservoir will naturally fall as it empties, until, eventually, there isn’t enough to force up oil. It’s possible to go some way towards maintaining pressure, by injecting water or gas into another (injection) well. The injected substance is forced through the pores in the reservoir rock, pushing some of the oil ahead of it. This process is known as secondary recovery. Water injection – or waterflooding – is almost as old as the oil and gas industry itself. It’s been used since the late 19th century, although it didn’t become standard until the second half of the 20th century. It continues to be very important for BP, still accounting, on its own, for around 60% of the oil that the company expects to recover. Adding waterflooding increases the amount of oil that can be recovered, with a typical value being 35%, although this can vary significantly depending on fluid properties and reservoir parameters. Injecting gas to maintain reservoir pressure is not as common as water injection, both because gas is a valuable – and marketable – commodity in its own right, and because more sophisticated machinery is needed to inject it. But it, too, is a technique that BP has used at large scale since the 1980s.
"The Ula field is now essentially only producing EOR oil, so without this technique, there would be no Ula. To my knowledge, this is the only offshore platform in the world that is just producing EOR oil."- Bharat Jhaveri
Enhanced oil recovery (EOR) is the generic term for techniques used to improve the amount of oil recovered from reservoirs – it is generally used to denote those that go beyond simple injection of water or gas to maintain pressure. The most widely used method is thermal EOR, which involves heating up the oil – usually using steam – to make it less viscous and, thus, easier to recover. Around two thirds of the world’s EOR oil production can be attributed to this technique. But it is exclusively used to recover heavy or very viscous oil, such as that found in oil sands, rather than conventional oil. So, BP’s efforts are predominantly focused on other methods, such as gas or chemical EOR. Enhanced oil recovery makes a real difference for BP’s production. The company’s massive Prudhoe Bay oilfield in Alaska is on track to achieve recovery of 60%, due, in part, to various EOR projects. At its Ula field in the Norwegian North Sea, essentially all the current production is due to EOR, as Bharat Jhaveri, BP senior advisor, gas EOR, explains: “The Ula field is now essentially only producing EOR oil, so without EOR, there would be no Ula. To my knowledge, this is the only offshore platform in the world that is just producing EOR oil. Some people consider EOR to be something that’s nice to have – the icing on the cake – but, in fact, it’s Ula’s lifeblood now.” Some of the most widely used forms of EOR build on basic gas injection to push the oil through reservoirs. At Prudhoe Bay, for example, BP processes the natural gas that is produced, along with the oil, into two EOR-optimised streams. Jhaveri says: “We take the enormous quantities of gas produced from the field, almost as much gas as Britain uses every day, and put it through an enormous refrigeration plant – effectively a $1 billion fridge – which takes it to -40 °C (-40°F). This enables us to isolate components in the gas, such as propane and butane. Then, we create one stream of ‘lean’ gas that’s virtually all methane, and another stream of what’s called miscible gas – because it mixes with the oil, unlike water – which includes propane, butane and carbon dioxide.” The miscible gas is injected into the wells in the oil zone to push more oil from the rock. “Initially, the gas and the oil are in two different states – or phases – but, then, some of the heavier components in the oil transfer into the gas, and some of the intermediate components in the gas transfer into the oil until, at the interface, oil and gas begin to look like each other. You can’t tell where the boundary is any more; they’re the same thing – and that makes it possible to push much more oil out of the rock with the injected gas.”
In practice: enhanced oil recovery technology at Clair Ridge
This technique is extremely effective – typically displacing 95% of the oil in the rock it reaches compared with typically 65% for water – but the sweep factor (the amount it spreads through the rock) is limited. So, the gas is alternated with injections of water to improve its sweep. The lean gas is used for something a little more specific to Prudhoe, as Jhaveri explains: “The whole structure of the field was originally full of oil, then, at some time in the geological past, the field tipped and a gas cap formed at the top of the reservoir. But the space taken by the gas had previously been full of oil. As the gas moved in, the oil drained down over the sand grains and some of it got stuck. “A good analogy would be tomato ketchup, which leaves isolated blobs on the side of the bottle as it flows. It’s the same in an oil reservoir – you end up with what’s called ‘relic oil’ coating sand grains in the gas cap. Only 8% of the oil sticks like this, so who cares? Well, we do actually, because there are 1 billion barrels of it at Prudhoe Bay. “You can pump water through the well forever, but this relic oil will never shift because it’s broken into patches – like the ketchup – and has lost its continuity, so it can’t flow. But, when you inject methane gas, components in the oil transfer to the gas. It’s analogous to having moisture on a surface and blowing warm air over it – the moisture vaporises. Then, we put the gas through the processing facilities, followed by the fridge again, which separates the vaporised oil, before recycling the gas to pick up some more oil. We’ve been doing this since 1987 and, eventually, it will help us to recover several hundred million barrels of extra oil.” There are several other enhanced oil recovery techniques, all with their own strengths and weaknesses. Which is used will depend largely on local conditions. Gas injection is perfect for Prudhoe Bay, for example, because of the natural gas produced at the field – but it would clearly be less desirable at a field where gas would have to be imported.
"There is no substitute for the lessons obtained through field trials and one of the other things that differentiates BP is that we have been prepared to commit to large-scale trials."
- John Peak
John Peak, vice president for BP’s Pushing Reservoir Limits technology programme, explains: “New ideas for improving recovery rates are constantly being developed. BP has deployed two advanced EOR techniques in recent years. The first, called LoSal ? EOR, exploits the discovery that low salinity water displaces more oil from rock pores than saltier seawater. The second, called Bright Water?, uses micro-particles that expand in the injection water when they warm up, thus blocking pores in freer-flowing rock zones and forcing the water through zones that were previously poorly swept.” As EOR techniques become increasingly sophisticated, so does BP’s understanding of what it takes to make EOR programmes work. Peak says: “Our experience has taught us that three important factors need to be in place: internal capability, external relationships, and focused deployment. “Reservoir rock structures are massively complicated, so the only way to be certain about whether an EOR method is going to work is to carry out proper tests in the lab and then in the field. You need world-class laboratories and inhouse expertise to do that and the fact that we have these at BP is one of the things that sets us apart.
“However good your inhouse resources may be, scientific understanding is advancing quickly, so it’s important to have relationships with key universities and other research institutions. We’re working with the University of Cambridge to improve our understanding of low salinity water, for instance. The ExploRe programme is another example of the type of relationships BP has established with universities.” ExploRe, running since 2009, comprises three projects – at the University of Copenhagen, University of Twente in the Netherlands, and the Max Planck Institute in Germany. BP funding enables these universities to assign teams of physicists, chemists, mineralogists, geochemists, geologists, engineers, mathematicians and biologists to various EOR research projects, the findings of which are shared with the industry. Peak continues: “When it comes to deployment, we know that to see a return on EOR investment, we must deploy at scale. There is no substitute for the lessons obtained through field trials and one of the other things that differentiates BP is that we have been prepared to commit to large-scale trials.” BP’s pre-eminence in the field of EOR was reflected in the invitation the company received to write a paper on the subject as part of a bigger piece of work on the topic of peak oil, for The Royal Society – the UK fellowship of leading figures in the fields of science, engineering and medicine. The lead author of the paper is one of the world’s leading academics in EOR, Ann Muggeridge - This link opens in a new window, professor of reservoir physics and EOR at Imperial College, London. Professor Muggeridge was also on the team that decided which universities to approach for the ExploRe programme, and what the research areas should be. She says: “If you think about all the technology we use to recover oil – the exploration, the platforms, all the hardware, the various EOR techniques and so on – it’s amazing that a cup of oil is still cheaper than a latte you’d buy from a café.
- Designer Water, Designer Gas and LoSal are all registered trade marks of BP plc
- Bright Water is a trade mark of Nalco Company