With demand for oil continuing to grow, the pressure is on to maximise the reserves.
Even 40 years ago doom-mongers were heralding the looming end of oil, but that, and every proclamation since, has fallen well short of the mark. New oil-field discoveries and technologies for extracting more oil from existing fields mean that there is enough oil remaining to last most of this century. However, less than 40 per cent of the oil is usually recovered from each field. To those working outside the industry that statistic may come as a bit of shock, but the reason is buried in the geology of oil fields.
Oil reservoirs are not underground caverns, but layers of sandstone with oil and gas held in the spaces between the grains that make up the rock. Allowing an oil reservoir to produce oil through declining natural pressure results in relatively low recoveries, so many fields inject water - waterflooding - into the oil-bearing rocks to increase the amount of oil that can be produced. Waterflooding sweeps oil towards the producing wells, but even then, much is often left behind. Globally, only about 35 per cent of the oil in place is extracted, leaving huge natural resources untapped.
“I think the amount that we can recover really depends on the reservoir,” says Alan Brook, manager of oil recovery at Shell. “What we do is assess this recovery factor against what we have derived as the reservoir complexity index, so we can try to evaluate the issues in increase and recovery for every reservoir. It is a common scale and that way we can identify recovery factors and what would be reasonably possible for any particular reservoir.”
While there is no exact figure, it has been known to extract in excess of 80 per cent of oil from some high-quality fields. “Under a thermal flood the range is much less than that,” Brook says. “Enhanced recovery is just a subset of those reservoir challenges so it requires a more integrated approach.”
Oil recovery involves a sequential approach. The primary approach is that oil is recovered under its own energy. Secondary production is all about supplementing that with pumping, water injection or gas injection and then there is the third strand, the advanced methodologies such as pressure recovery. “EOR can actually come at any phase of the lifecycle,” Brook adds. “You can apply enhanced recovery at a secondary or primary mode.”
Alan Brodie, business developer advisor at PTC contemplates the same challenges: “It would be nice to think that an oil reservoir is like a great big water reservoir and you could just pour oil out of it, but oil is contained within the strata of the earth. Over millions of years it has become choked up a little bit and the ionic activity of strata within the earth to the well bores that we are drilling is limited. Consequently it is a challenge to get all of the oil out.
One of the most well-established methods of increasing oil flow is ‘artificial lift’, a technology that falls into the second tier of techniques. At its most basic this comprises of a pump - electrical, mechanical or hydraulic - either at the surface or at the bottom of the well. On land it is usually the rod pump (the familiar ‘nodding donkey’) that can be seen in most onshore oil fields. These have a rod that goes from the surface all the way down to the bottom of the well, and a bucket with a ball valve in the bottom to raise oil out of the ground.
The electrically driven drives are widely used for electrical submersible pumps that comprise a centrifugal pump and an electric motor located at the bottom of the well and connected to the surface by a high-voltage power cable.
Hydraulic-driven pumps are essentially jet pumps where high-pressure stream is injected into the well bore and through conservation of momentum energy is added to the well-bore fluids.
All of those technologies are in essence a pump. There are different drive mechanisms for the pump and different ways of delivering the motor force to the oil, but at the end of the day, each of them add energy to the system.
There are other lift methods, grouped under the category of ‘gas lift’. “The oil well contains a concentric series of pipes,” Brodie explains. “The innermost pipe is the pipe through which the oil is produced and we pump gas through the annulus space around the innermost pipe. There is a valve arrangement as deep as possible in the well where the gas that we pump down the annulus is able to pass from the annulus into the tubing. Once it gets into the tubing, the gas mixes with the produced oil and has the effect of reducing the density of the column of produced oil. As you reduce the density of the column of the produced oil, what you are doing effectively is reducing the pressure at the bottom of the well. If you reduce the pressure at the bottom of the well, the differential pressure between the reservoir and the well bore increases and the well flows at a faster rate.
“Gas lifters are a competing methodology that is fundamentally different from all of the pumping methods because it changes the produced fluid’s properties advantageously so that the wells flow more readily, whereas the other ones add energy to the produced fluids properties. It does the same thing and results in a lower bottom-well pressure and the wells flow more advantageously, but just by a different way.”
Gas lifting however, does have its disadvantages as Brodie explains it can be one of the most dangerous things that you can do in an oil well. “What you are doing is introducing to the oil well, a large volume of pressurised gas into that annulus space around the production tubing,” he says. “In the event that there are any incidents at the well head that might cause the gas to leak from that annulus, the platform facilities will be exposed to a significant amount of high-pressure gas coming out at them and the potential for an explosion is enormous.”
Its danger was effectively displayed during the Piper Alpha disaster that befell the North Sea Oil platform in 1976. It was not the main cause but a contributory factor. Once the fire took hold and the wells started to produce up the annulus instead of up the tube the safety guard in the tubing was sealed. But the gases allowed the production to continue up the annulus instead of the tubing.
Despite that inherent danger, gas lift is very widely used around the world. One of the advantages with electrical submersible pumps it that you can add as much energy as you want, whereas gas lift is only increasing density and you can only take that so far.
Size can be a constraint on submersible pumps because when you are working at depths of several thousand metres the 5,000V cable, a 600hp motor and a very long multi stage pump need to fit inside a 6in diameter pipe. So an electric submersible pump can be 100ft long and have a 5.5in diameter.
Low salinity recovery
There are the three broad families of enhanced recovery - gas, steam or chemical, and they each address different reservoir challenges. Steam or thermal is applied where you have got heavy crude. Gas injection is particularly effective where you have lighter crude and you are trying to displace it and go after the residual saturation. Finally the chemical methods are successful when trying to overcome one or both of those challenges as well as microscopic trapping.
“We have taken a strategy of going after all three,” Brook says. “We have a bit of a unique philosophy that we want a full EOR tool kit and through that we can apply the right solution for any particular reservoir challenge. So for thermal floods we have got steam projects in Canada and California, Omar in the Middle East and the Netherlands.
“Gas injection, we have got quite an extensive history in CO2 flooding from the Permian Basin. We did exit the Permian in 2000, but our current gas projects tend to be our gas projects in Oman and also the Caspian.
“We do have new ideas for the future, not all that I can talk about of course. I think what you will see is a lot of combinations of these techniques. One of the more interesting ones that we are maturing is low-salinity oil flooding, where we have an ongoing water flood or a water flood being panned. We have primed a technology where simply by manipulating the ionic contents of the water, we can improve recovery and something like polymer flooding added on top of that can be a very low-cost addition because it also reduces the polymer requirement with the reduced salinity. So those kinds of hybrid ideas I think is where you will see a lot of progress in the future.
The Clair Ridge development in the Shetland Isles is a £4.5bn development that will is expected to begin producing oil in 2016 at the rate of 120,000 barrels of oil per day at peak. It will also be the site of the first offshore enhanced oil recovery (EOR) scheme using reduced salinity water injection (LoSal EOR). The developers - BP, ConocoPhillips, Shell and Chevron - expect that this technology will deliver 42 million barrels of additional oil compared with waterflooding with conventional seawater.
The technology was tested successfully four years ago in a field trial in the Endicott field, Alaska where low-salinity water was injected in one well and the incremental oil production observed in another. The Endicott trial confirmed the laboratory trials at full scale and gave the consortium the confidence to attempt this on a full field.
“LoSal EOR and other technologies are increasing the world’s energy supplies, improving recovery rates and getting more for every dollar we invest,” Bob Fryar, BP’s executive vice president for production, says. “LoSal EOR has immense potential for increasing the amount of oil recovered from the ground. If it can be successfully applied to similar fields around the world it will increase the world’s recoverable oil by billions of barrels.”
In conventional waterflooding, injected water flows through layers of porous reservoir rock displacing oil from the injection well to the production well. The pore spaces often contain clays to which oil is bound. LoSal EOR, using reduced-salinity water, releases a lot more of the bound oil and pushes it to the production wells.
“Oil industry wisdom says you shouldn’t inject anything too fresh or the clays within the oil-bearing sandstones can swell and reduce the ability of the oil to flow,” Jackie Mutschler, head of upstream technology at BP, says. “So BP looked at the fundamental chemistry which makes the oil molecules stick to the rock surfaces in reservoirs. What we discovered is that by reducing the salinity, and hence the ionic concentration of the injected water, more molecules of oil could be released from the surface of the grains of the sandstone rock in which they’re held.”
The chemical studies showed that the oil molecules are bound to clay particles by bridges of divalent cations - missing two electrons as compared with the neutral atom - such as calcium or magnesium and, in high-salinity water they are compressed to the clay surface by electrical forces. By reducing the salinity, this force is reduced and the bridges are able to expand allowing the divalent cations to be swapped for non-bridging monovalent ions such as sodium. The oil molecules are then freed to be swept towards the producing wells.
The history of EOR is largely onshore, but with discoveries now being largely offshore there are significant opportunities and EOR in offshore projects is growing. “We have recently signed an extension to our production contract in Malaysia,” Brook says. “It’s all about implementing enhanced recovery in the offshore Malaysia fields. We are also key partners in some EOR projects moving ahead in the North Sea. I think you will see that the challenges around logistics, weight and space limitations, offshore platforms, wider well spacing, these are the sort of things that will be groundbreaking projects and trend setters for those that follow.”
EOR is playing an ever greater role in oil production that many believe is heralded by the continued high price of oil. Its use is changing too. Previously it was an add-on, something to be attempted when the oil flow slowed. But in modern field planning it is factored in from the start and can enhance oil flow from early in a field’s lifecycle.
“Technology and cost play hand in hand,” Brook says. “You think of technologies as a kind of pipeline for developments. There are a number of technologies that are proven and applied in the industry today and are economic on a certain type of reservoir. So what we have got in the development pipeline are ways that can expand the application and drive down costs on some of those proven ones.
“The biggest challenge is a human capability question, to have the ability to implement and operate these projects efficiently.”
With the growing ability of oil engineers to extract greater proportion of oil from each field, allied with the growth of unconventional oil and production, the hydrocarbon age is set to extend beyond our lifetimes and likely those of our offspring as well.
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