Piecing it together

01.12.2015
Developing the Maria oil discovery would probably never have got off the ground if operator Wintershall had thought along traditional lines. Luckily, imagination was given free rein.

| Alf Inge Molde

Illustration: Wintershall

Bit by bit.
Wintershall describes the negotiations with the neighbouring licences as complex, wide-ranging and time-consuming. But everything is now in place for bringing Maria on stream in the fourth quarter of 2018.
(Illustration: Wintershall)

 

A plan for development and operation (PDO) of this field was approved by the Ministry of Petroleum and Energy on 4 September, despite the biggest oil recession since the late 1990s.

Maria lies 230 kilometres from land and 25 kilometres east of the Kristin field on the Halten Bank in the Norwegian Sea, and the process leading to the PDO was demanding.

But project director Hugo Dijkgraaf at the Norwegian arm of the Germany company says the detailed preliminary work was essential for turning the development into a reality at all.

Semi-submersible Songa Delta drilled the discovery well, 6406/3-8, in 300 metres of water during the summer of 2010. That was two years after production licence 475 BS was issued in the 2008 awards in predefined areas.

The Halten Bank is no frontier region. Neighbours include big producing fields such as Åsgard, Heidrun and Kristin. And the prospect was first drilled in 1986, but without much success.

Thin

This earlier well targeted the perceived top of the reservoir, and should have yielded the most crude. But the oil-bearing strata proved thin, and the licence was therefore relinquished. New three-dimensional seismic data unavailable in the 1980s then gave the geologists an opportunity to interpret the structure in a different way.

Their re-assessment concluded that the oil-bearing zones were at their thickest in the southern and northern flanks of the reservoir, which has a saddle-like formation in the centre.

That proved to be the case, and the first well proved 60 million barrels of oil to the south. The same amount was found by an appraisal well drilled on the northern flank in 2012.

Furthermore, studies of the reservoir and drainage strategies allowed another 60 million barrels to be matured – revealing a field containing some 180 million barrels of oil equivalent.

The water depth meant that the licensees opted for a subsea development. Two approaches were studied, including a tie-back to an existing platform nearby.

A floating production, storage and offloading (FPSO) unit was the alternative, but Wintershall quickly found that this would an expensive solution.

However, a round of tie-back discussions with the partners on the nearby producing fields also made it clear that none could offer everything Maria needed.

Something

However, each could provide something. Kristin was able to process the oil, Heidrun offered assistance with water injection, and the Åsgard B platform was in a position to support gas lift.

The last of these needed to be channelled through the Tyrihans D subsea facility. Finally, Åsgard C had the capacity to accept Maria oil for export.

So the challenge for the project was to determine how much had to be spent on each installation to serve Maria. And more than 100 kilometres of pipeline would have to be laid.

Once the jigsaw had been laid, however, Wintershall and its partners found themselves with a much cheaper solution than installing a dedicated FPSO. And it was technically feasible.

“We think we’ve been extremely creative,” emphasises Dijkgraaf.

According to Norway’s regulations on using installations belonging to others, fields with spare capacity are duty-bound to make a detailed evaluation of such requests.

Tie-backs to existing platforms and other infrastructure make sense both for developers and for the taxpayers who bear the bulk of cost.

“Achieving this involves finding a formula for sharing risk and profit,” explains Dijkgraaf, who describes the negotiations as complex, wide-ranging and timeconsuming.

Statoil is the operator for all the installations involved in the Maria project, but the counterparties to the negotiations were other partners who formed varying constellations in each licence.

Many sessions were also required with the government in order to reach a settlement. During the final phase alone, Dijkgraaf met the NPD and the Ministry of Petroleum and Energy 35 times.

New ground

The project director feels that Wintershall broke new ground in many respects with its approach, and believes that many others will follow its lead.

Kalmar Ildstad, deputy director general of the NPD, and Tove Francke, who was responsible for work on the Maria PDO at the directorate, also think that many more satellite projects will be pursued on the NCS.

The majority of the 100 or so discoveries which remain to be developed off Norway are too small to support a stand-alone solution.

However, many lie close to existing infrastructure in the North and Norwegian Seas, and could tie into this as capacity becomes available in order to achieve a profitable project.

That approach has the added benefit of helping to extend production from fields where new satellite fields connect to their facilities.

“Maria has set a Norwegian record for the number of tie-ins for a single development, and demonstrates that much is possible if the willingness to collaborate is present,” says Ildstad.

Wintershall expects to spend a total of NOK 15.3 billion on the development – more than NOK 2 billion below the original investment estimated.

Part of the saving was achieved through optimisation in the planning process, but Dijkgraaf does not deny that developers get a lot for their money now that suppliers are hungry for orders.

The Maria licence, for example, was able to charter Odfjell Drilling’s Deepsea Stavanger rig for 574 days at a cost of roughly NOK 1.5 billion – considerably less than the rate two years ago.

There has been no question of postponing a development in the hope of securing even more favourable prices. Given today’s oil prices and the investment climate, however, Dijkgraaf admits that the licensees would not have considered an FPSO.

“That solution was challenging when oil prices were USD 110 per barrel, and would certainly have been out of the question when they were down to USD 45. So we had to be creative.”

 

Norwegian Continental Shelf no.2-2015

Main page - Contents
Bente Nyland on the NCS: Glass is half-full
The interview: Petroleum minister calls on companies to invest
Special report: 50 years
Norway’s offshores sector safer than before
Safety carries a cost
Seeking to cut documentation
Eldar Myhre and son Aslak discuss what oil has done with Norway
NPD profile: Diskos database crucial for exploration success
Making huge volumes of offshore data available
Adding up to acclaim
Rockshot: Tight formations
Geology: Many benefits for society
www.norskpetroleum.no: Find facts about the NCS