Norway bids to unlock Norwegian Sea discovery with hydraulic fracturing

The Norwegian Offshore Directorate believes innovations within hydraulic fracturing will solve one of the largest puzzles of them all – the Victoria discovery in the Norwegian Sea.

Victoria was proven by an Exxon exploration well 6506/6-1 in the year 2000. Total took over the operatorship six years later, and an appraisal well was drilled in 2009. The work to mature the discovery, given the state of technology at that time, indicated that profitable production would be challenging, and the acreage was relinquished in 2018.

‘We want to inspire the companies to take another look at the Victoria discovery. Yes, it’s a tight reservoir at significant depths, with both high temperature and high pressure, as well as a high content of CO2. Nevertheless, a study indicates that current well technology, combined with hydraulic fracturing, could allow production of substantial gas volumes,’ said Per Valvatne, senior reservoir engineer at the Norwegian Offshore Directorate.

‘This is one of the largest remaining gas discoveries on the Norwegian Continental Shelf (NCS) that is still not covered under a production licence. This is acreage that the companies can apply for in the next APA (Awards in Predefined Areas). Previous work on the discovery has shown around 140 billion standard m³ of gas in place, and the study reveals that four wells could yield production of 29 billion m³,’ said Arne Jacobsen, assistant director of technology, analyses and coexistence at the Norwegian Offshore Directorate.

Opecs, a British consulting company, has assisted the directorate in this study, which also includes a geomechanical study of the discovery. Opecs’ report shows that use of modern hydraulic fracturing technology can improve well productivity enough to ensure profitable production from Victoria.

The discovery is located at a water depth of 400 m, approximately 4800 m below sea level. The Dvalin field (10 km away), Heidrun and Åsgard (50 km away) are potential tie-back points.

The study shows that the aforementioned four wells could produce 10 million m³ of gas per day; a level that can be maintained for nearly two years. This would mean a total production of 29 billion m³ over a production lifetime of 30 years.

Another finding in the study indicates that there may even be room for additional wells, which would further increase recovery.

Jacobsen said: ‘It’s important to get development started while there is existing infrastructure to tie into: that’s why we believe efforts to unlock these reservoirs must be increased now.’

Hydraulic fracturing has mainly taken place in chalk reservoirs on the NCS. The Victoria discovery is situated in a sandstone reservoir, where fracking experience is limited on the NCS. ‘This was the reason for bringing in UK-based Opecs, as the Brits are more experienced when it comes to these types of fields,’ said the Norwegian Offshore Directorate in a statement.

Jacobsen said that both the technology and expertise are better than was the case 10-15 years ago: ‘Fluids and propping agents used in hydraulic fracturing have improved, the vessels used are better, and we’re also able to deal with higher reservoir pressure and temperature. These operations can also be done faster and with greater reliability, thus reducing costs and uncertainty.’

He added that the study shows that producing Victoria may now be commercially profitable: ‘Our hope now is that this will spark someone’s interest, and a willingness to commit to this huge proven gas resource. Moreover, we also have several discoveries on the NCS in tight reservoirs. The study shows that using today’s technology could mean that hydraulic fracturing can unlock substantial values on the challenging Victoria discovery. If we can solve the challenge there, then we can also set our sights on other challenges. As resource managers, we believe that hydraulic fracturing will become a key technology for realising the resource potential in tight reservoirs.’