Elgin/Franklin: What Could Have Been Done Differently?

Abstract

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 123681, ’Elgin/Franklin: What Could We Have Done Differently?,’ by Eric Festa, Total E&P UK, originally prepared for the 2009 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 8-11 September. The paper has not been peer reviewed. At the time of project sanction in 1997, Elgin/Franklin was the largest high-pressure/high-temperature (HP/HT) development in the world. It required innovation across the full range of operator activities. Eight years after production began, it is fair to say that Elgin/Franklin has not only achieved the aims of the initial project, it has clearly surpassed them. With hindsight, using this experience, combined with a decade of further progress in technology, some Elgin/Franklin-development features could have been optimized further. Introduction The Elgin and Franklin gas/condensate fields were discovered in 1991 and 1986, respectively, in the Central Graben area of the North Sea. The reservoirs are 5500 m deep and present abnormally high pressures (1100 bar), extreme temperatures (200°C), and significant levels of carbon dioxide and hydrogen sulfide. Facilities consist of two wellhead platforms, one normally unattended (Franklin) and the other located over the Elgin field. Glenelg and West Franklin are two HP/HT discoveries made after the initial development of Elgin/Franklin that were put on production in 2006 and 2007, respectively. Initial Field Development Field-Development Plan—1997. The development was based on 12 wells (seven on Elgin, five on Franklin) and included the recovery of two predrilled appraisal wells. Provision was included for a second Elgin wellhead platform, also bridge connectable to the process-utilities and quarters (PUQ) platform, to be installed later if warranted. The project included the installation of a normally unmanned wellhead platform on the Franklin field, with Franklin production transferred to the Elgin permanently manned PUQ platform by means of a multiphase interfield pipeline system (Fig. 1). The total estimated cost for the project represented a large investment, especially in the low hydrocarbon-price environment prevailing at the time. The Elgin/Franklin project distinguished itself from other offshore installations in the UK continental shelf in that gas processing on the PUQ was designed to yield commercial-quality gas, satisfying both the Interconnector and National Transportation System specifications. On arrival at Elgin PUQ, the high temperature of the production demanded special cooling equipment. Titanium compact heat exchangers (CHEs) were selected because of their reduced weight compared to conventional shell and tube coolers.