What will it take to develop offshore heavy oil?

Ingolf Søreide

August 1, 2014

The Mariner development concept. Images from Statoil. 

The Mariner heavy oil field took 40 years, 12 oil companies, five seismic surveys, and 18 exploration/appraisal wells to get to where it is today. Ingolf Søreide explains how heavy oil production has improved and where it is still challenged.

It’s mid-1977 and a geophysicist is analyzing 2D seismic data acquired in UK Block 9/12. The survey happened to include some data from the neighboring block. In this 9/11 Block data, the geophysicist discovers a feature that is promising enough to persuade Union Oil management to acquire a license.

Plans to drill were quickly drawn up and the semisubmersible Dixilyn Field 97 was chartered to evaluate the prospect. The first well in 1981 hit oil. Unfortunately, the rig was also hit when a supply boat collided with it. After a visit to the shipyard, three more wells quickly followed, two of which tested promising amounts of oil. The only problem was that it was heavy, 14° API, in fact. Not like the light 38°-40° API found in Brent and Forties.

Both Union Oil and the company who did the original survey, Seismograph Service Ltd., are long gone. But Mariner, the field they helped find, held an estimated two billion barrels of oil.

Fast forward 40 years to 2017. A brand new six-leg platform has been installed in 110m of water. There are three modern rigs on site and a large floating, storage and offtake unit (FSO) to take the produced oil away. The development cost Statoil and partners JX Nippon and DYAS in excess of US$7 billion. So why did it take 40 years, 12 oil companies, five seismic surveys, and 18 exploration/appraisal wells to reach this point?

The answer lies in the heavy oil. These types of reservoirs are typified by low flow rates and early water breakthrough, often within a few months. Once water does break through, it completely dominates the production. In addition, energy is required to lift the oil, since it is unable to flow on its own. Wells are commonly equipped with expensive downhole electrical submersible pumps. Working in harsh downhole conditions, the pumps need regular maintenance and replacement using expensive rigs. Once the oil is on surface, the challenges continue. Separating heavy oil from water is difficult and water disposal is a challenge. As if that was not enough, the refiners would rather take the light Brent, and heavy crudes often sell at a discount.

So what made the difference on Mariner? In one word, technology. Specifically, the application of tools such as multi-lateral branch wells, autonomous inflow control devices and a novel rig to change out pumps when necessary. Modern advanced seismic surveys have enabled us to see reservoirs that were invisible to the specialists in 1977. Another game changer is a well design that injects light condensate downhole, mixing with the heavy oil. The resultant product is a blend that refiners are very happy to take.

So is it case closed for heavy oil? Unfortunately, not yet. Mariner made it because it holds 2 billion bbl. What will it take to unlock smaller offshore deposits?

Certainly, subsea well and production technology are likely to be key. Increasing the recovery rate has to be at the top of the list. Steam assisted gravity drainage is commonly applied onshore, but offshore the energy costs are prohibitive. Techniques such as polymer flooding are showing promise, but application offshore needs improvement. Mariner will keep producing for at least 30 years, and in that time it will see many new technologies implemented.

I suspect the answer lies in the focused application of all the technologies mentioned and many more. If shales or heavy oils and the like are what the future is pinned on, something has to change. The message is repeated often. Operator and service partners must work closely to develop the tools badly needed. Operators themselves will have to work closely, regardless of commercial affiliations. The importance for our children’s energy future may just usher in a new way of working together. As I have said on many occasions, “we are in this together.” Oh, and a higher oil price would be nice, but we leave that up to the gods of supply and demand.

Left: The Category J rig concept. Right:  A Category J rig, artist’s impression.

Statoil’s Mariner development up close

The development of the Mariner field will contribute more than 250MMbbl reserves with average production of about 55,000bbl/d over the plateau period from 2017-2020. The expected date for production start is 2017.

Mariner’s location in the UK North Sea. 

The concept chosen includes a production, drilling and quarters (PDQ) platform, based on a steel jacket, with a floating storage unit (FSU). The topsides are being fabricated by Daewoo Shipbuilding & Marine Engineering in Korea. The FSU is being built by Samsung Heavy Industries, also in Korea. Spain’s Dragados Offshore was awarded an engineering, procurement and construction contract for the steel jacket in cooperation with the UK offices of Canada’s SNC Lavalin. Offshore installation of the platform jacket is scheduled for mid-2015, followed by topsides during 2016.

Drilling will be carried out from the PDQ drilling rig, with a jackup rig assisting for the first 4-5 years. Statoil is planning to use a new category J rig on Mariner, operated by Noble Corp. The category J rigs will be able to operate at 70-150m water depths and drill wells down to 10,000m. Category J is a tailor-made jackup rig for operations in harsh environment on both surface- and subsea wells in the shallow-water segments on the NCS.

The overall development proposal includes 50 wells and 92 sidetracks at Mariner and four wells at Mariner East. More than 140 reservoir targets for production or injection are planned for Mariner. While the number of well slots at the platforms is less, this will be solved using multi-branch technology, side-tracks and reuse of slots.

Mariner is on the East Shetland Platform of the UK North Sea, about 150km east of the Shetland Islands. It consists of two shallow reservoir sections—the deeper Maureen formation, at 1492m, and the shallower Heimdal reservoir, at 1227m. The oil is heavy with API gravities of 14.2° and 12.1° and viscosities at reservoir conditions of 67cP and 508cP, respectively for Maureen and Heimdal.

Statoil is the operator of the field with 65.11% equity, with partners JX Nippon Exploration and Production (UK) (28.89%), and Cairn Energy (6%).

Ingolf Søreide
gave a keynote speech about heavy oil at the SPE’s European Artificial Lift Forum in Aberdeen, SPE EuALF 2014, on 17 June. He is a vice president with Statoil, heading up the UK North Sea Mariner field development, which received government approval in February 2013. Søreide has almost 30 years’ experience in the oil industry, mostly at Hydro and Statoil. He has been involved in R&D in Statoil and is member/chairman of the board of directors in Christian Michelsen Research. He recently moved to Aberdeen to lead the Mariner project through the execution phase. He holds an MSc and a PhD in Petroleum Engineering from the Norwegian University of Science and Technology in Trondheim, Norway.