World's Longest Electrically Heated Flowline Allows HP/HT Field Tieback to Existing Host

Abstract

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 161572, ’HP/HT Field Development Tied Back to an Existing Host,’ by Trevor Crowe, Shell, and Jean-Paul Koninx, SPE, and Crispin Slater, A/S Norske Shell, prepared for the 2012 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed. The Linnorm gas/condensate field in the Norwegian Sea is technically challenging. The high-pressure/high-temperature (HP/HT) reservoir contains gas with CO2, H2S, and traces of mercury. Although the gas is relatively lean, the associated condensate has waxy properties. Although there are production facilities within 30 to 70 km, this discovery was initially seen as “stranded” gas because of the absence of an export route with available capacity. The wells and subsea concepts would push the limits of existing technology and require some world-first solutions for what will be the highest-temperature subsea field development on the Norwegian continental shelf with the world’s longest electrically heated flowline. Introduction The Linnorm gas discovery was made during the first half of 2005 in the Haltenbanken area offshore Norway. Well 6406/9-1 found a 180-m net column of lean gas in a gas-down-to situation in three Jurassic reservoir zones, all under HP/HT conditions (180°C, 800 bara). Two reservoir zones were production tested, both with good results. The field was further appraised by Well 6406/9-2 in 2007, successfully determining the gas/water contact in the key reservoirs. Several follow-up exploration wells all proved dry. This meant that the projected hub development for the Halten South area was no longer feasible. The likely way forward for Linnorm then was in the åsgard pipeline became available (currently estimated to occur later than 2020). The project was put on hold in 2007 because Linnorm was not expected to be developed before the 2020s. In summer 2008, an opportunity to accelerate the development of Linnorm was identified by making use of potential ullage in the newly commissioned onshore gas-processing plant at Nyhamna, built to process gas from the giant Shell-operated Ormen Lange field. This would require a new 200-km trunkline, the cost of which made the development commercially marginal. The solution was found by entering a new joint venture, the Norwegian Sea Gas Infrastructure project. The next challenge was to select an option for gas processing. Rather than an expensive new-build platform on Linnorm, the choice was made in mid-2011 for a subsea development with a tieback to the Shell-operated Draugen oil platform. In December 2011, the development concept was confirmed as a two-template, five-well subsea development, with a 55-km directly electrically heated (DEH) flowline tied back to Draugen, and 15 million m3/d of gas-processing capacity installed on Draugen (Fig. 1). Subsurface Uncertainties An extensive wireline formation-sampling program showed that the dis-covered gas is generally fairly dry, with high CO2 content, some H2S, and, on average, 50 Μg/std m3 of mercury. The condensate/gas ratio (CGR) varies per reservoir, with evidence for vertical compartmentalization in up to six different reservoir layers. Reservoir quality is variable, with some very good sands but also large sections with lower-quality tight sandstone. The high variability in reservoir quality across the reservoir leads to a number of specific challenges.