It's hard to quantify accurately recovery rates on the UK Continental Shelf (UKCS).
Estimates from the Department of Energy and Climate change put it at about 46%. Global estimates point to somewhere between 30-35%. However, the well known dictum, "big fields get bigger," hasn't been created without substance.
Thanks to its reservoirs, the dictum is well suited to the North Sea. Yet, could even more be had from this basin where, as in other basins, more oil is left behind than extracted.
The question is being tackled by author and former BP and Shell geologist Mike Shepherd (pictured) at the Devex subsurface focused conference being held in Aberdeen next month. He spoke to us ahead of the event.
What have been the key technologies to enable improved recovery rates?
The biggest impact in the high recovery factor of the North Sea has come from water-flooding from the start of development. It’s helped that the oils are pretty light.
Reservoir description has improved out of all recognition from the early days and this means locating the remaining oil in existing fields that much better. In particular the vast improvement in seismic quality is a major factor. Let’s mention the development of 3D and 4D seismic in passing. The development of 3D geological modelling packages for creating computer models has been a major development too. These help you understand the reservoir in intimate detail.
Let’s also mention enhanced oil recovery methods and new drilling techniques such as horizontal wells.
Is there still room to improve recovery rates yet further?
Yes. A top-in-class recovery factor of 46% is not a ceiling. A few years ago, the Norwegians developed an initiative to see if they could take recovery to 55%.
“The Norwegian group OG21 www.og21.org have been set a task to figure out how the recovery factor (RF) for the fields offshore Norway can be improved. Under existing development plans the RF is already predicted to be 46%. Their goal is to improve this number to 55%. This they hope to achieve by the application of new drilling technology, EOR and other improvements. Already fields on the Norway Continental shelf see extensive use of EOR projects, especially WAG (water alternating gas) schemes.
The Norwegian oil company Statoil have given themselves a target to achieve a RF of 65% on average from their platform-operated fields and 55% from subsea-operated fields.“
And a quote from the start of my first book, a textbook on oil recovery, Oil Field Production Geology (AAPG 2009):
“The basic observation is that the amount of oil recovered from the world’s oil fields has historically been poor. Typically more oil has been left behind in oil fields than they have ever produced. It is interesting to speculate as to how much the recovery factor can be improved globally by enhanced reservoir management.
"It is worthy of note that an upside improvement in recovery of 13% would add almost as much oil supply as has been consumed by the world to date. It would take a heroic effort to get this much oil out of our reservoirs, but if we could, then this would go a long way to providing a solution for the world’s energy problems.”
What are the barriers?
Economics, is the short and sweet answer. A low oil price does not help.
What technologies should we be keeping an eye on for the future?
I reckon there is one area where despite all the progress, current reservoir management practice lacks focus. And I would argue if we could find that focus, reservoir recoveries would improve substantially.
This is the technology which Shell calls Locate The Remaining Oil (LTRO) and the implementation of these techniques led to spectacular results in their Brent fields in the 1980s and 1990s. Yet, surprisingly the techniques are not widely used.
To implement LTRO, there is one thing you have to know about reservoirs. Only about five or six large-scale features control how the reservoir performs and once you know what they are, then you understand your reservoir well enough to start looking for the remaining oil. The problem is that every reservoir is different and it takes a lot of effort to determine what these features are. I wrote a paper on how to do this with Caroline Gill of Shell, Gill, C.E. and M.Shepherd, 2010. Locating the Remaining Oil in the Nelson Field, presented at the 7th Petroleum Geology Conference, London.
Now here’s the thing, the features are often subtle and easy to overlook. If you don’t know they are there, the most intricate geological model for a field is never going to work adequately without these features represented implicitly in the model. I am convinced that much bypassed pay is overlooked because many geological models miss this trick.
Even once you have done this, the techniques for locating the remaining oil are not widely used. I mention some of them in my textbook and also in the Nelson paper.
Mike Shepherd was born in Aberdeen and witnessed the arrival of the oil industry to the city in his teenage years. Later working for BP and Shell planning oil wells in the North Sea, his childhood dream of becoming a geologist was realized with over thirty years experience in the oil industry. His previous work includes the textbook Oil Field Production Geology, used for postgraduate study both in the UK and abroad.
Devex is on May 18-19 at Aberdeen Exhibition and Conference Centre.
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