Offshore heavy oil economics

Jeannie Stell looks at offshore heavy oil development economics with an eye on the current low-price environment.

ExxonMobil expects its 52-well Hebron development project offshore Newfoundland to bring in first oil in 2017.  Photos from ExxonMobil.

Even as onshore unconventional hydrocarbon developments fall victim to the downward spiral of oil and gas prices, offshore heavy oil developments continue to prove promising for significant group of exploration and production companies. This is especially true for state-owned entities unconcerned with sustainable revenues. Although the cost of exploring and developing offshore heavy oil is high due to the difficulty of producing, transporting and refining heavy oil, major international energy companies continue to develop heavy oil fields in an effort to replace reserves. For example, despite the current crude price drop, China continues to develop its heavy oil reserves because its state-owned companies are not particularly concerned with profits, unlike their peer publically held companies. Heavy oil, typically defined as <22° gravity API, represents a valuable resource, but defining the potential proves to be problematic as total-resource reports vary greatly. According to Chevron, heavy oil comprises about 50% of known oil resources but represents just one in 10 bbl of production. New global investment to develop this 8 trillion bbl resource could double production output by 2025, reports the company. According to estimates by London-based Visiongain, a business-intelligence provider and trading partner with the US Federal Government, on average up to 20% of the world’s remaining oil could be sourced from onshore and offshore heavy oil deposits. The company predicts that the global market could reach more than US$50 billion this year, with production reaching more than 6 MMb/d. The majority of the billion-dollar price tags will be spent for cold heavy oil projects because many of the world’s largest heavy oil markets have well-established cold heavy oil projects, states the company.“As reserves of lighter crude oils dwindle and the rate of new discoveries decreases, oil and gas companies are increasingly looking to alternative hydrocarbon sources to plug the gap,” reports Robin Ray, energy analyst for VisionGain. “Heavy oil is one of those sources.”Such heavy oil plays offer significant growth and investment opportunities as international companies join to form partnerships for development. In the long run, as commodity prices recover, energy demand grows and major conventional oil discoveries become increasingly rare, the economics of heavy oil should steadily improve.

Today, more than 30 countries are known to possess recoverable heavy oil reserves, according to Halliburton. “Led by Canada and Venezuela (Canada’s heavy oil deposits rank second only to Saudi Arabia in total oil reserves, active heavy oil-producing countries also include the US (California), Mexico, Brazil, Russia, Indonesia, China, Colombia, Ecuador, Iraq, Kuwait, Saudi Arabia, Chad and Angola,” reports the company.

For now, many of the major exploration and production companies are continuing to eke out profits as they work offshore heavy oil exploration and developments.



In February 2015, Petrobras discovered new oil accumulations in offshore concession BM-C-35 (exploratory block C-M-535) found in the Campos Basin post-salt layer (OE: March 2015). The discovery was made while drilling well 1-BRSA-1289-RJS, also known as 1-RJS-737, and informally known as Basilisco. The well was drilled at a water depth of 2214m and about 143km from the city of Armação dos Búzios on the coast of Rio de Janeiro. Heavy oil has been found at 3190m and at 3521m. The consortium of concession BM-C-35, operated by Petrobras (65% interest) in partnership with BP (35%), are testing the extension of the discoveries and the concession’s exploratory potential.

Also, Brazil’s Parque das Conchas project, a Shell development, is continuing and is notable as the first project field development incorporating subsea oil and gas separation and subsea pumping for the company. During two development phases, the fields were developed by 13 wells tied-back to the centrally located Espirito Santo FPSO, moored in 5840ft of water. The first phase developed four fields, and the second phase will develop the fifth field. The double-hulled Espirito Santo FPSO has enough power and heat delivery systems to drive the system and process heavy crude oil. With a production capacity of 100,000 b/d, the Espirito Santo facility will process heavy crudes that range from 16° to 24° gravity API.


In late 2014, ExxonMobil tapped Cameron for the supply of large-bore wellheads, production trees and risers to be installed at the 52-well Hebron development project offshore Newfoundland. First oil is expected in 2017. The Hebron heavy oil field near Terra Nova, Hibernia and White Rose fields is about 220mi offshore the eastern coast of Canada’s Newfoundland and Labrador in the Jeanne d’Arc basin about 302ft deep, and is estimated to contain between 400 and 700 MMbbl of recoverable resources (OE: November 2014). The project includes the Hebron, West Ben Nevis and Ben Nevis fields from four reservoirs, including the Lower Cretaceous Ben Nevis, the Lower Cretaceous Avalon, the Lower Cretaceous Hibernia and the Upper Jurassic Jeanne d’Arc reservoirs. Production will begin in the Ben Nevis, Hibernia and Jeanne d’Arc reservoirs on the Hebron field, with gas storage in the Ben Nevis reservoir of the West Ben Nevis field. Oil production is expected to be enhanced via water injection, and produced gas will be used for artificial lift. Hebron includes a stand-alone gravity-based structure consisting of a single main shaft to encompass the wells, support the production and living topsides, and separate the produced oil, gas and water, as well as treat produced water and compress gas. Produced oil will be exported via a looped pipeline and two loading points to offload to ice-strengthened tankers.The Ben Nevis and Hebron fields are expected to produce 80% of the 20°API heavy oil on the project. Oil production capacity is planned for 119,506 to 176,115 b/d with treating capacity of 188,694 to 283,041 b/d of produced water for disposal overboard. Gas will be compressed at a rate of 53.0 to 70.6 MMcf/d. Storage capacity is 1.45 MMbbl.


Peng Lai 19-3 in the Bohai Bay is China’s largest offshore oil field. The Bozhong Block 11/05 play is found in 75ft water and produces 21°API heavy oil. ConocoPhillips (49% interest) operates the project for its partner, Chinese state company CNOOC (51%). The field was development with an installation of a 24-slot wellhead platform and the leased, barge-type Bohai Ming Zhu FPSO that includes processing and storage facilities, accommodation quarters, power generators and a flare. The Bohai Ming Zhu FPSO is capable of processing up to 45,000 b/d and storing more than 360,000 bo.


Cairn Energy has updated its JM-1 exploration well offshore Morocco. In the Upper Jurassic, the well confirmed the presence of heavy oil over a 110m gross interval as tested in the 1968 MO-2 well, 2km from JM-1. The company plans to correlate core and log data with other wells on Cap Juby to assess the hydrocarbon potentials.


EnQuest is further developing its program for heavy-oil play Kraken found in the UK sector of the North Sea on Block 9/2b. EnQuest (45% interest) operates the field for its partners Celtic Oil (30%) and Nautical (25%). Development drilling will begin during 2H 2015 with the Transocean Leader, a mid-water semisubmersible. EnQuest’s program for Kraken during 2015 includes installation of subsea hardware, including manifolds for the first drill center, two templates for the second drill center and installation of the mooring system for an FPSO.

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