Several fields in the Norwegian and British part of the North Sea are producing from sand injectite reservoirs. Availability of broadband seismic data and successful production from earlier developments has led to renewed interest in injectites as exploration targets (Exploration Technology report on the NCS by Westwood Energy -read “Integration is the key to success”). Recent discoveries were made in the injectite play at Frosk and Froskelår by Aker BP and the Agar-Plantain discovery of Azinor Catalyst.
Although the existence of injectites has been known since early in the 19th century, the importance of these deposits as oil reservoirs was not realized until the 1990’s. It all started with the making of a Plan for Development and Operations (PDO) for the Balder field. The operator ExxonMobil soon understood that sandbodies above the main reservoir were of a different nature than the deep marine sandstones that were sourced from the East Shetland Platform. Similar sand bodies were also recognized in the oil fields Jotun, Grane and Sleipner East on the NCS as well as in several fields in the UK sector (Alba, Harding, Chestnut, Gryphon; Hydrocarbon Habitats, Injectites, 2017). But most of these fields were developed before the importance of injectites was recognized.
Rediscovery- the Volund Field (GEO 8/2016)
Well 24/9-5, was drilled by Fina in 1993, and is believed to have targeted turbidite sands located below the Balder seismic marker. 6 m of oil-bearing sandstone were found in the Grieg discovery. In 1994, the 24/9-6 appraisal well was drilled and encountered 11 m of oil-bearing sandstone. However, Grieg was declared uncommercial and interpreted to lie within a turbidite fan/channel complex made of massive grain-flow sand deposits.
Marathon Oil picked up the licence in 2003 and redid the mapping and seismic modelling. Marathon was convinced the reservoir was made of injected sandstones. The Hamsun Prospect exploration well 24/9-7 was drilled in 2004 and targeted a seismic amplitude anomaly thought to be a sand injection feature updip from the 24/9-6 well. The 24/9-7 well encountered 37 m of gas and 12 m of oil. This well was then side-tracked downdip (24/9-7 A) and encountered 6 m of gas, 32 m of oil and 6 m of water. An updip side-track (24/9-7B) only encountered 5 m of thin gas-bearing sandstones. The final appraisal side-track (24/9- 7 C) was drilled laterally and encountered 29 m of oil on 19 m of water. Pressure and log data confirmed one common oil– water contact (OWC; 1995 m true vertical depth subsea (TVDSS)) and gas–oil contact (GOC; 1891 m TVDSS) throughout the field. These four wellbores confirmed the existence of hydrocarbon-bearing sandstone within the seismic anomaly, interpreted as a sandstone injection complex. (Schwab et all, 2014). The plan for development and operation (PDO) for the Volund Field (renamed from the Hamsun Prospect) was approved in 2006, and development drilling commenced in 2009.
The “rediscovery” and development of the Volund field and satellite fields Viper and Kobra is thanks to the increased understanding of the nature of injected sand complexes in the Tertiary. This comes from the integration of new depositional models, with high-resolution seismic data encouraged by production data from analogue fields. Marathon and, later on Aker BP has developed a very good understanding of the injectite play in the Viking graben.
Injection of sands
The injected sands in the North Sea originate from deep marine depositions. These deep marine sands were overlain by anoxic shales. Because of the sealing shales, the water in the sands was not pushed out of the pore space while being buried but the sands became fluidized when the pore pressure increased. This also created fractures in the overlying shales. The sands became unstable and mobilized at a depth of several hundred meters. These movements were likely triggered by volcanism associated with earthquakes in the North Atlantic during Eocene times according to Ivar Skjærpe from Aker BP (“et spektakulært reservoir”).
The process of remobilisation and injection of deepwater sands produces very high-quality reservoirs often with multi-Darcy permeability. The porosity in the Hermod formation reservoir in the Volund field is on average 34 prosent with 1-6 darcy permeability. Injectite reservoirs are very complex and therefore high-quality data and a good conceptual model are needed to be able to predict reservoir presence.
Despite the complex nature of the reservoirs and the limited thickness of the sands, the reservoirs can be very well connected, resulting in high well rates and recovery factors. The Harding field in UKCS is for example estimated to have a recovery factor in excess of 70%. Production from the Gryphon field was doubled late in field life by developing the thin “wings” of the reservoir. (Jackson et al. 2011: AAPG Bulletin).
The injectite play in the Viking Graben is an obvious cross-border play with fields and discoveries on the Norwegian side in the Alvheim area and on the UK side close to the Beryl field. Also the development options for these new discoveries might lie across the border.
Azinor Catalyst made the Eocene Agar oil discovery in 2014 with well 9/14a-15A, which encountered a 11m oil-down-to in high quality Eocene Frigg Formations sands (“Found up to 50mmboe“). New 3D broadband (Geostreamer) seismic data were used to delineate the Agar discovery and significantly de-risk the Plantain prospect before drilling the appraisal well. Ultra-far stack amplitudes were used as an indication for reservoir presence and in a short video Azinor shows how the prospects were mapped using AVO class II and III pay indicators constrained by the discovery well, in between the Balder pods.
Well 9/14a-17B, drilled in 2018 on the Agar-Plantain prospect encountered excellent quality oil and water bearing sands. This wellbore delineated the eastern extent of the hydrocarbon discovery. The Agar side-track encountered a 20 metre (gross TVT) interval of very high-quality oil-bearing sands, with no identified oil-water contact. Based on preliminary analyses, Catalyst believes the Agar-Plantain discovery holds recoverable resources of between 15 and 50 million barrels of oil equivalent. Further appraisal is planned in 2019.
Frosk and Froskelår
Aker BP has been leading the way in the injectite play on the Norwegian side of the Viking graben and has recently launched a drilling campaign around their Frosk discovery from 2018 (read “drilling campaign around Frosk”).
Frosk proved 50 mmboe of oil in sand injectites, i.e. remobilized sand from the Heimdal and Hermod formations into the Hordaland Group. The reservoir is characterised by very to extremely good reservoir properties. Well 24/9-12S encountered a 10 m oil column in 40m sandstones and well 24/9-12A found 30m oil-bearing sands. Frosk will be developed via Bøyla and a test producer will be put online in 2019 according to partner Lundin.
Aker BP just recently announced their success in finding oil and gas in well 24/9-14S Froskelår Main (“Oil and gas in Froskelår”). Froskelår is part of the same injectite complex as the Frosk discovery. Not many details are released since operations are ongoing, but Aker BP estimates the gross discovery size within a range of 45-153 mmboe. Aker BP has received a permit to drill appraisal well 24/9-14A immediately after finishing the discovery well.
The other wells in Aker BP’s 2019 drilling campaign are Rumpetroll (well 24/9-13) and Froskelår NE. Rumpetroll will test another sand injectite complex near the Frosk discovery. It has a large upside potential with estimated predrill resources of 45 to 148 mmboe (93mmboe according to Lundin).