Understanding EOR

Elaine Maslin

April 1, 2015

EOR is taking off offshore, yet scientists at the University of Aberdeen believe more work needs to be done to understand the link between reservoir properties such as wettability and fluid flow to help in order to truly benefit from EOR, Elaine Malin reports.

Prof Yukie Tanino (right) in the University of Aberdeen’s laboratory.  
Images from the University of Aberdeen

Enhanced oil recovery is playing an increasing role in the global offshore production environment.

With a portfolio of increasingly mature fields, operators have been seeking to increase recovery rates, from around 20% to upwards of 60% and higher as enhanced oil recovery (EOR) methods and technologies improve and reservoir understanding increases.

Increasing recovery rates could have a dramatic effect on global reserves. According to Shell’s 2014 Enhanced Oil Recovery report, “Just a 1% increase in the global efficiency of hydrocarbon recovery would raise conventional oil reserves by up to 88 billion bbls, which is the equivalent to three years of annual production at today’s level.”

EOR methods range from waterflooding (including smart water or low salinity water technologies), miscible gas floods, and polymer flood. CO2 injection for EOR and storage is also being considered.

However, while these technologies have been developed by oil companies, and have been deployed already, trialed or due to be trialed, scientists at the University of Aberdeen believe that more work needs to be done to understand the link between fundamental reservoir properties, specifically wettability, and fluid flow, which in turn impact how well EOR methods work.

What’s more, they’re also looking at how oils with different chemical compositions interact with rocks of different compositions to influence reservoir wettability.

It’s complex work, but understanding the fundamentals will help the industry to understand why what they’re doing works – or not, says Dr. Yukie Tanino, lecturer at the university in the Environmental & Industrial Fluid Mechanics Group in the School of Engineering.“What is the optimal reservoir wettability for oil recovery,” she asks. “Once we can answer that we can think about how we can achieve that wettability using conventional EOR methods.”

Wettability is key to understanding fluid flow in the reservoir as it controls where fluids are distributed at the pore-scale. Some surfaces repel water (hydrophobic, or “oil-wet”) and some repel oil (hydrophilic, or “water-wet”). The university is carrying out corefloods using synthetic oil to simulate different wettability scenarios in the lab.The main focus so far has been on identifying quantitatively correlations between wettability, as characterized by the contact angle of oil-contacted grain surfaces, and waterflood oil recovery. Future work will focus on chemical signatures of wettability inversion during waterfloods.

Examples of samples prepared by the University of Aberdeen.

A further development of the research program at the university has seen Tanino and her colleague Dr. Stephen Bowden in the Department of Geology and Petroleum Geology assembling mm-scale models of reservoirs in microfluidic chips. This approach has two main benefits. First, it provides a petrographic perspective (a geologist’s view through a microscope) of what’s happening. Second, the small scales of the model reservoir speeds up experiments, permitting a much bigger range of variables to be investigated.

But that sounds like more work – what is the benefit? “The main challenge of laboratory investigations is that there are a number of properties that control oil recovery, and each of these properties can take on a range of values: simply comparing two different rock types, two different oil types, and two different water types at five different temperatures and pressures would require two hundred or more experiments, each lasting one or two months,” Tanino says.“Just comparing these cases would take my laboratory several years of corefloods at the conventional (cm-) scale!

This isn’t practical and so the main benefit of using lab-on-a-chip methods is that it becomes feasible to systematically investigate a wide range of variables.”

Bowden says: “One of the first experiments that sprung to mind demonstrated that two comparable oils, with small differences in their chemistry, can exhibit identical waterflood behavior in one rock type, but then differ significantly in another rock type.“What’s so odd is that the oils are so similar, and in one rock type they did indeed behave in a similar way, while in the other case they were so different. To me it seems unfair, but if an operator wasn’t aware of this they could easily make erroneous assumptions about future water production rates and overall recovery. This is very interesting for us, but clearly a bad day in the office for an engineer.“Nature’s final cruel trick is that many fields and reservoirs not only have geological heterogeneity (different rock types), but also a mix of oil types – often because many different charges of petroleum have filled a reservoir.”Tanino and her colleagues are assembling a library of these small scale experiments. “The intent is that a user – an engineer, geologist or production chemist – could search the experimental archive and investigate the effects of oil chemistry, rock type, and water composition on wettability to better evaluate EOR options,” she says.

“There is a lot of interest now on the effects of changing water chemistry (BP’s LowSal, Bright Water and Brackish water, for example). It makes sense if you are injecting water to displace the oil that the consequence of using one or another type of water is considered. We are looking at the issue from the other side of the equation: how will different mineral and oil types in a rock interact with a given water type? This takes us back to the fundamental question of what influences wettability, and then the question of how can changes in wettability – either natural or engineered – impact production?”