Wants to open up tight reservoirs

The challenge was issued during a seminar at the Norwegian Offshore Directorate’s offices today, 1 October.

The presentation of "Victoria" (pdf)

"Victoria" was proven by 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. The discovery was part of production licence 211.

“Victoria” is situated in the western part of the Norwegian Sea, around 10 kilometres from Dvalin.

Substantial volumes

“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,” says 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 cubic metres of gas in place, and the study reveals that four wells could yield production of 29 billion cubic metres,” says Arne Jacobsen, Assistant director of Technology, analyses and coexistence at the Norwegian Offshore Directorate.

British experience

Opecs, a British consulting company, has assisted the Directorate in this study, which also includes a geo-mechanical 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 metres, approximately 4800 metres 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 cubic metres of gas per day; a level that can be maintained for nearly two years. This would mean a total production of 29 billion cubic metres 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.

Urgent

Jacobsen says 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 somewhat 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.

Jacobsen notes 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 says 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.”