Prime example of “missed pay”

In 1984, Mobil Exploration Norway, at that time operator of the Statfjord field, drilled what was deemed to be a dry well.

Located only 25 km north of the Troll field, the primary objective of 35/11-1 was to assess the hydrocarbon potential in Middle to Upper Jurassic sandstones. Lower Jurassic sandstones were considered a secondary objective. No significant shows were, however, recorded in neither cuttings, sidewall cores nor conventional cores. In addition, available data indicated water gradients in the reservoirs. The only positive indication of hydrocarbons, at the time, was that the background gas increased dramatically when drilling into the Upper Jurassic Sognefjord Fm. Nevertheless, NPD classified the well as dry.

Some 20+ years later, Wintershall reanalysed the well data and concluded that 35/11-1 could have been an example of “missed pay”.

“The main reason for questioning the old analyses was that the CPI log interpretation was hampered by a casing shoe in the middle of the Upper Jurassic Sognefjord Fm,” says Per Bakøy, now with Pandion Energy, but then with Spring Energy that was a partner in the licence.

“We now know that the high gas readings in the Sognefjord Fm originated in poor quality sandstones, and that the well drilled through the lowermost part of the reservoir at the very edge of the structure. It is also noteworthy that the operator drilled into the reservoir with a 17 ½ inch bit. Nowadays, that would not have been possible.”

Bakøy has reanalysed many wells on the Norwegian continental shelf for the purpose of finding “missed pay”-sections.

“35/11-1 is a prime example,” he says.

In 2009, 25 years after the initial “dry” well, Wintershall drilled 35/12-2 (Grosbeak) higher up on the same structure, and the well proved oil and gas in the Sognefjord and Fensfjord Fms and light oil in the Brent Gp. Recoverable volumes were at that time estimated to 35-190MMboe.

“The unusual large resource range was due to marginal reservoir quality in the Sognefjord Fm, meaning that the recovery factor was very uncertain,” Bakøy recalls.

In 2011 Wintershall appraised the discovery with 35/12-4A and 35/12-4S. Well 35/12-4 S was drilled in the south-eastern part of the structure and encountered an oil column of 40 metres in the Brent Group (Ness Fm). Well 35/12-4 A was drilled at the top Brent Group on the north-eastern part of the Grosbeak structure. The upper part of the Ness Fm consisted of thin layers of sandstones, but no hydrocarbons were found.

The results were considered negative, and Wintershall gave up the prospect. From then on Grosbeak became known as a stranded discovery.

Wellesley Petroleum, founded in 2015, had petroleum geologists with intimate knowledge of the Grosbeak discovery, and together with Petoro carved out PL 248I from PL 248 that was awarded in 1999. From December last year Wellesley has had a busy schedule in the area drilling 5 wells on 3 prospects: Kallåsen, Serin and Grosbeak. While Serin was dry, Kallåsen was a technical discovery.

In September 2018 Wellesley spudded 35/11-21S and encountered a total oil column of about 90 metres in the Ness and Etive Fms, while 35/11-21 A encountered a total oil column of about 50 metres in the Ness Fm. Also, an oil column of about 8 metres was encountered in the Fensfjord Fm. Before drilling Wellesley had a best case of 115MMboe. Following the completion of these wells the preliminary best estimate has now increased to 190MMboe.

It is good reason to believe that a supposedly dry structure will be developed after assessing the discovery along with nearby discoveries and prospects. Thanks to geologists who have the courage to question old truths.

Better reservoir understanding

CGG/Robertson has reanalysed more than 50 wells within the NVG survey area with respect to biostratigraphy, chronostratigraphy and lithostratigraphy. The result is a total new understanding of the Upper Jurassic depositional system of the Horda Platform.

While the original interpretation, based on NPD reported tops, looked upon the reservoir as Intra Heather sandstones, the new interpretation – taken from the NVG Well Study – looks upon the reservoir as a combination of two sandstone bodies of different age: An older blocky, homogenous sand (Early Oxfordian age) and a younger fining upwards sand package (Kimmeridgian age).

Consequently, the new interpretation shows that the younger Kimmeridgian sand body is not encountered in well 35/11-14 S and that reservoir quality of the Early Oxfordian sandstones can be identified in well 35/9-6 S, which was not indicated with the original tops.

Both diagrammes are shown in GEO 08/2018.