The oil & gas industry is no stranger to water injection and waterflood methods to increase recovery. One operating company is working out details on how to tailor the water used in waterflooding techniques to boost offshore recovery rates. Jennifer Pallanich talks with the supermajor about the ‘designer' waterflooding technology the company hopes to use soon, perhaps in the Gulf of Mexico.
Shell's designer waterflood technique reduces the salinity of injected water to increase oil recovery by an expected 5-10%. The low-salinity water, injected at the beginning of a waterflood effort, releases the oil from the reservoir to drive up recovery rates. The supermajor believes the process has potential, especially offshore where other enhanced oil recovery techniques are more costly. Because seawater is so abundant in the offshore arena, Shell sees a floating mobile desalination plant that produces low-salinity injection water, combined with polymers, as a viable offshore increased oil recovery method.
Val Brock, R&D manager for Shell's IOR/EOR effort, notes the industry on average only recovers about one-third of the barrels of oil in the ground overall, potentially less in an offshore environment. ‘That leaves two-thirds of the oil behind . . . it is a shocking number,' he says. ‘We've got to get the most out of what we've got.'
The problem is a fairly widespread one of ‘oil wetness,' or the tendency of oil to attach itself to the rock in a reservoir, Brock says. ‘What we try to do is change that and cause the rock to let go of the oil.'
David Brooks, team leader for IOR research at Shell, says using the right ionic composition of water is useful in causing the rock to release the oil. Using water with certain ionic compositions can also help remove some harmful components, such as sulfate, in places prone to oilfield scale, he adds, and it can help avoid souring. Water's appeal increases offshore because it's plentiful from seawater.
Brock acknowledges Shell is not the only operator interested in the technology, also known as low-salinity flooding and smart water. ‘It's an idea that's been around for about 10 years or so,' he says. ‘It's building momentum across the industry.'
Of course, Brock notes it takes a bit of science to come up with the right level of salinity in the water to cause the rock to release the oil without falling apart. Brooks says straight drinking water, for instance, could damage the reservoir.
‘It starts with understanding the mineralogy of the reservoir,' Brooks says. For example, he says, oil and clay both hold negative charges while hard ions, such as salts, provide a bridge between the oil and clay minerals. ‘It's very important to know the characteristics of the materials in the reservoir.'
Brock agrees: ‘It's the surface chemistry that is the key to this . . . and understanding almost at a molecular level how brine, rock and crude interact.'
Next comes determining the minimum salinity and the maximum hardness needed in the water to improve the recovery levels. At that point, it's important to assess how the mix will affect recovery rates and whether it will damage the reservoir. Predictive tools, experience with minerals, and experiments all come into play in determining the level of salinity necessary for increasing oil recovery, Brooks says. ‘The window varies from field to field and reservoir to reservoir,' he says.
And it wouldn't be necessary to use the same level of designer water until the field depletes, Brooks says. After a certain period – say, a couple of years – of pumping the designer water, he says, it would be possible to use produced water if desired. Then, he adds, the equipment needed for fine-tuning the water could be moved to use in another field.
Desalination, nanofiltration and reverse osmosis are methods used in creating the designer water. ‘By combining the flow streams that come out of this kind of kit we can achieve the right kind of salt and hardness content in the water we want to put in the ground,' Brock says.
Brooks estimates using properly designed water in the waterflooding effort can improve oil recovery levels by 5-10%. Shell has proved the technology onshore – including reducing the saturation at one onshore well from 35% to 21% – and is working to identify a suitable location for its first offshore application. Designer waterflood will be ‘relatively straightforward to implement' offshore, Brooks says. Right now, Shell is removing some sulfates from the seawater it's using to waterflood its Ursa field in the Gulf of Mexico. ‘We're looking at places like Ursa where we can go a bit farther with some additional filtration equipment,' he says. ‘Ursa gives us the confidence that this technology can be applied to other fields in the Shell portfolio.'
The designer waterflooding method would not be applicable in water-wet situations where the oil doesn't stick to the rock, Brock notes. Additionally, there is some ongoing research on how to apply the method to carbonate reservoirs. ‘We've seen that by changing the water composition, recovery can be increased, but the mechanism is less well understood on how the mineralogy, brine and crude interact. I wouldn't say it's not applicable, but it's still in research [for carbonate reservoirs],' he adds.
‘We're at the beginning here. It's an emerging technology. It's very new. We at Shell think it's very exciting,' Brooks says.
And on the horizon beyond designer water? Brock sees the possibility of using polymer flooding to increase the water viscosity, thereby sweeping more oil out of the wells. He envisions a one-two punch, or a ‘double whammy' of designer waterflood combined with polymer flooding, where the lower salinity would also reduce the polymer requirement. ‘We're excited about that kind of hybrid scenario.' OE
The PNC pulsed neutron capture tool detects how fast thermal neutrons are captured, measuring the capture cross section (S) expressed as capture units (cu). Of the naturally occurring atoms, chlorine has by far the largest cross section. Therefore, Swater is a strong function of salinity. In fact, the cross section of oil and fresh water are so similar that the tool cannot differentiate between them so that the anticipated saturation change could not be detected directly after the low-salinity injection. This problem was overcome by injecting a second high salinity slug which allowed quantitative comparison of Logging Points 2 and 4. Results of the low-salinity flooding were evaluated over the interval 3133.3 to 3138.8 mahd. A detailed picture and the average values over this interval is shown above. The average change in saturation over the injected interval is calculated as DSw = 14 + 1.5% PV.
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