Hydraulic Fracturing Unlocks Potential of Europe’s Largest Reservoir

Abstract

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 205250, “Hydraulic Fracturing at Clair: Unlocking the Potential of Europe’s Largest Reservoir,” by Alistair M. Roy, SPE, Graeme H. Allan, SPE, and Corrado Giuliani, SPE, BP, et al. The paper has not been peer reviewed. _ Greater Clair, Europe’s largest oil field, has two existing platforms, Clair Phase 1 and Clair Ridge, on production with the potential for a third platform targeting the undeveloped Lower Clair Group (LCG) to the South of Phase 1. In some areas, however, low matrix quality and lack of natural fractures were the dominant characteristics, resulting in lower production rates. The authors write that fracturing technology brings opportunities to unlock poorer Phase 1 and Ridge reservoir areas. Introduction Reservoir Description. The Clair field is 75 km west of the Shetland Islands on the UK Continental Shelf within the extensional Faroe-Shetland Basin. The Old Red Sandstone reservoir is divided into two lithostratigraphic units, the Upper and LCG. The LCG contains the bulk of the oil in place and underpins the Clair development. The reservoir is characterized by large variations in facies and permeabilities. The LCG is subdivided into six units, I through VI, based on variations in sedimentary facies and heavy mineral assemblages. Development drilling preferentially targets the highest quality reservoirs in Units V and III. The LCG is defined as a dual-permeability system with a variable fracture distribution. Three main scales of fracture features are observed in the core: fault-related, fracture corridors unrelated to large offsets, and lower-density joint-type networks. Open fracture density varies considerably by stratigraphy, with the highest densities in Units V and VI. Field Development Phases. Exploration Well 206/08-1A discovered Clair in 1977. Clair underwent a protracted appraisal program before sanction of the Phase 1 development in 2001. The commercial viability of the reservoir was not confirmed until an extended well test in 1996 proved that oil rates from 15,000 to 20,000 BOPD could be sustained from long horizontal wells targeting high-productivity fracture zones. The scale and complexity of the reservoir drove a phased multiplatform development. Phase 1 began production with 20 producer and injector wells coming online between 2005 and 2011. Five additional wells drilled during 2016–2017 increased platform production by 70%. The second platform, Clair Ridge, came online in 2018, and the development wells drilled to date have encountered varying degrees of natural fractures. Design and Characteristics of Well A23 for Hydraulic Fracturing Candidate Well for Propped Fracturing. Horizontal Well A23 was completed in March 2017. The lateral penetrated the low-permeability unfractured Unit VI of the LCG in the Graben area of Phase 1. It crosses the core/graben fault, which is assumed to act as a baffle to communication between Zones 1 and 2 and Zones 3 and 4. Well A23 was put on gas lift production in 2017, producing approximately 1,300 BOPD. The well trajectory was designed to remain 40 m above the shale layer and to facilitate roughly transverse fractures within Unit VI Upper by drilling perpendicularly to the maximum horizontal stress to overcome vertical drainage issues.