Advanced Drilling in HP/HT: Total's Experience on Elgin/Franklin (UK North Sea)

Abstract

Technology Today Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Abstract Drilling high-pressure/high-temperature (HP/HT) exploration wells remains a challenge, despite years of experience acquired by the drilling/completion industry. Development wells have further expanded the envelope of performance of the technologies and procedures required to deliver production from HP/HT fields safely and economically. Now comes the time of drilling and completing infill wells, which paradoxically appear to be more difficult as depletion increases and the mud-weight window (MWW) diminishes. To overcome this problem, intense engineering work has been carried out to better understand the effect of the depletion on compaction and fracturing gradient, to design and qualify new drilling-mud systems combined with stress-caging techniques, and to prepare contingent solutions with the deployment of expandable- and drilling-liner technologies. Three infill wells have been drilled, completed, and put on production by Total in the Elgin/Franklin fields on the UK Continental Shelf. This success was achieved through severely depleted reservoirs—with depletion greater than 800 bar—and has enabled phased HP/HT developments and deep exploration beneath depleted horizons. Overview of the Elgin/Franklin Extreme-HP/HT Fields The Elgin/Franklin fields present an extreme combination of pressure and temperature (1,100-bar virgin pressure and 200°C, respectively) and remain the largest HP/HT gas/ condensate fields developed in the British sector of the North Sea. The fields are approximately 200 km northeast of Aberdeen in the Central Graben area. Following discovery and appraisal from 1985 to 1994, development started in 1996 with two unmanned wellhead platforms tied back to a central production facility. Eleven wells were drilled and put on stream, with deviations up to 50°, in an average drilling duration of 120 days. These wells were drilled before a predefined limit of depletion level had been reached, a level at which the MWW closes—calculated for Elgin/Franklin as 100 bar. First oil production occurred in 2001. Later, two satellite structures, Glenelg and West Franklin, were drilled and put on production through the existing installations in 2006 and 2007, respectively, (Fig. 1). The reservoirs consist of Jurassic sandstones buried at a depth exceeding 5300 m. The primary reservoir is the Fulmar, also called Franklin, sands. Reservoir fluids are gas/ condensate with a bottomhole pressure of 1100 bar and temperature of 190°C. The Fulmar reservoir is underlain by the Pentland reservoir with bottomhole conditions of 1150 bar and 200°C (Fig. 2). Despite the depth, the main reservoir shows significant porosity and permeability, allowing strong productivity. Up to 30% porosity and 1-darcy permeability are found in some Fulmar layers Individual wells in the field can produce up to 3.5×106 m3/d of gas with associated condensate. Surface production conditions are 860-bar wellhead shut-in pressure with an associated temperature of 180°C. The produced effluent contains 3 to 4% CO2 and 30 to 40 ppm H2S. Initially, field gas production reached 14.6×106 m3/d, with 24 000 m3/d of condensate. This combination explains the strong need for technology and in-depth engineering for these wells.

Flow rate and source reservoir identification from airborne chemical sampling of the uncontrolled Elgin platform gas release

“…This was significant in that it supported the inference that the source was comparatively small and depressurizing: i.e that the gas leak was indeed from a restricted source 20 such as may be found in the Hod Formation and not from the main production depth (Bergerot, 2011).…”

Response to RC1

“…Compared to the first flight on 30 March 2012, the second flight on 3 April 2012 found significantly weaker plumes, suggesting that the gas source was depleting. This was significant in that it supported the inference that the source was comparatively small and depressurizing: i.e that the gas leak was indeed from a restricted source such as may be found in the Hod Formation and not from the main production depth (Bergerot, 2011).…”

Flow rate and source reservoir identification from airborne chemical sampling of the uncontrolled Elgin platform gas release

“…This was significant in that it supported the inference that the source was comparatively small and depressurizing: i.e that the gas leak was indeed from a restricted source such as may be found in the Hod Formation and not from the main production depth (Bergerot, 2011). Information released by Total indicated that the main production depth had been plugged prior to the blowout.…”