In the years before the oil price crash of 2014, the offshore industry spent bucketsful of money building infrastructure while the price of oil was high and looked like it was never coming down. It was the oil and gas version of making hay while the sun shines. It would be easy to say “who knew?” in relation to the price crash because not many analysts and observers expected to see such a precipitous and sustained drop in the price of a barrel of crude causing a significant collapse in development activity.

Since then license groups in offshore sectors around the world have struggled for the most part to find a way to bring new production onstream at a price that made the investment of new capital worthwhile. Many in the service and supply sectors trimmed personnel, reduced the size of construction vessel fleets and curbed new capex to match the reduced demand for project support.

Approval of new projects—with water depth not appearing to be a major factor in deciding what would and would not be developed—has dropped from the heady days of five years ago. But it was not quite the fall from the cliff edge that some have suggested.

Weighing Norwegian opportunities

A look at what fields are due to soon come onstream and what fields were either already approved or near to what is now the Holy Grail—the final investment decision (FID)—suggests the industry has not exactly been sitting on its hands for the last three years (Table 1). The industry has weighed up its offshore opportunities in a measured fashion while watching the cost of development come down to a level where money can be made even with the barrel of oil now finely balanced in the $50/bbl to $60/ bbl range.

TABLE 1. Offshore opportunities have kept E&P companies busy weighing development options for their fields since 2014. (Compiled from industry reports)

 

Nowhere is this truer than in Norway. Traditionally viewed as a high-cost sector, it has been perceived as an indigenous company sector once Statoil took over Mobil’s assets in the 1980s. Before Statoil absorbed its compatriots—Saga Petroleum and Norsk Hydro—these three companies dominated the sector. Most of the very big fields, such as Åsgard, Kristin, Ormen Lange, Oseberg, Snorre and Troll, were developed by the Norwegian companies with a major emphasis on deploying new technology often developed in-country. The sector was certainly seen as one where almost anything could be tried with the support and encouragement of the authorities and technology organizations.

New international players have emerged, as well as some new domestic players seen as replacements for Saga and Norsk Hydro, that like the opportunities in and the proximity of Norway to their home countries. Companies like Swedish firm Lundin, German entities Wintershall, VNG and DEA, Centrica out of the U.K. and domestic operator Aker BP have worked their way into the Norwegian scene. These companies, including Statoil, are taking advantage of Norway’s big portfolio of platforms to bring a raft of smaller finds into production and give them a new profile on the Norwegian Continental Shelf.

Developing fields

Wintershall has been making its move into the Norwegian North Sea for a number of years. It first acquired the Brage asset to cut its teeth on offshore operatorship and has now completed its first development at Maria (6406/3) in the Haltenbanken area of the Norwegian Sea. This project exemplifies what can be done with relatively small reserves (29 MMbbl and 2.3 Bcm [81.2 Bcf]) in the midst of a well-developed offshore sector.

The company is taking full advantage of its field’s proximity to three Statoil platforms in the area. The fluids from the subsea field flow 20 km (12.4 miles) to the Kristin semisubmersible unit and then onward to the Åsgard C floating storage unit. The field also will have production support of gas lift from the Åsgard B semisubmersible unit through a seabed template on the Tyrihans Field and water injection from the Heidrun tension-leg platform (TLP).

In roughly the same area is DEA’s Dvalin subsea gas project with 18 Bcm (635 Bcf) in reserves. The company is making use of the Heidrun facilities located 15 km (9.3 miles) away. It will have four wells on a single template feeding gas to the TLP and then onto the Polarled pipeline installed to handle gas from the Aasta Hansteen Field located another 7.5 km (4.6 miles) away.

VNG is yet another German company getting into the Norwegian sector. It is bringing together three finds— Pil, Bue and Boomerang—under the banner of Fenja. Located 32 km (20 miles) from the Njord Field, the field will include two seabed templates with production wells as well as water and gas injection wells. This complex of fields will come onstream in 2020 to coincide with the redevelopment of the Njord A semisubmersible unit. Operational since 1997, it underwent a major life extension program in 2012 to enhance production life and to accommodate production from the Hyme and Njord Northwest Flank satellites. The production semisubmersible unit was towed to shore in 2016 for major modifications for life extension and to facilitate development of the Bauge satellite field.

Another subsea satellite brings an additional merger and another German company into a new development. Centrica of the U.K. and Bayerngas Norge have merged to form Spirit Energy. The company’s first project will be the Oda Field, formerly Centrica’s Butch prospect, with reserves of 48 MMboe. The field was discovered in 2011 in the southern part of the Norwegian North Sea about 13 km (8 miles) east of the Ula Field. When it comes onstream in 2019, it will produce 35,000 bbl/d from two subsea wells tied back to the Ula platform and one seawater injection well for pressure support, per the plan and development operation (PDO) submitted to the Norwegian Petroleum Directorate (NPD).

Aker BP submitted three plans for development, two of which are subsea, to the NPD in December 2017. The Skogul Field is the smallest of the two subsea projects submitted. It will be developed as a subsea tieback to the Alvheim FPSO unit. Aker BP estimates recoverable reserves of the field to be about 10 MMboe.

The larger development of the two is at the Ærfugl Field in the Norwegian Sea. The plan calls to develop two deposits—Snadd and Snadd Outer—in two phases as a subsea tieback to the Skarv FPSO unit. Aker BP estimated remaining reserves of the Ærfugl Field to be at about 275 MMboe. The first phase, due onstream in 2020, will include three new subsea wells plus the already drilled A-1H well. A second phase that will require more work to confirm could be onstream in 2023.

Sailing forward

As the biggest player in the sector, Statoil would hardly want to be left out of all of this satellite activity. More than five years ago, the Norwegian state company launched its “fast-track” initiative to bring as many of its small finds onstream as quickly as possible while infrastructure was still in place. The intention also was to keep project teams together so that they could improve upon their performance and aim to reduce the costs of developing fields with small reserves.

The first field to come into production under this scheme was Visund South in 2012, and it appears that Gullfaks Rimfaksdalen was the last in the summer of 2016, although Statoil would not confirm this. This initiative, having covered at least 20 projects, was quietly closed for reasons undisclosed by Statoil.

With the installation of a new NOK 1 billion (US$125.5 million) gas processing module onto the unit, the Troll C semisubmersible unit will be not shut down any time soon. The upgrade is to improve the efficiency of production from the Fram Field. In addition, the Byrding Field will be developed with a single multilateral well linked into the Fram Field pipeline infrastructure at the Fram H-Nord template.

In 2017 Statoil filed a PDO for the Trestakk Field that will be a large satellite field adding an estimated 76 MMboe to the Åsgard complex. A subsea template will have three new oil production and two gas injectors and tie into an existing producer.

The Trestakk Field in the Norwegian Sea is located about 20 km south of the Åsgard Field and will consist of one subsea template with four well slots and an additional satellite well. The subsea installation will be tied back to the Åsgard A facility for processing and gas injection. (Source: Statoil)

 

These fields fit into the mold of small subsea projects but Snorre 2040 does not. The field was first developed by Saga in the early 1990s with a TLP and a 20-slot seabed template. Initial reserves were put at 750 MMbbl, but extensive drilling and the addition of a production semisubmersible unit have seen that figure rise to more than 1.7 Bbbl. Current production is more than 80,000 bbl/d, boosted by three recently drilled producers that were drilled at a cost similar to a single earlier well and added 30% more fluids.

This latest expansion will add at least 200 MMbbl to that total. Originally to be based around a new production facility, Statoil is now opting for a full subsea development with six seabed templates and at least 24 new wells. This new scheme will see capex on this field extension plan fall by 30% to 40%. The FID remains to be made at this writing.