First True Tight Gas (< 0.1 mD) Horizontal Multiple Fracture Well In The North Sea

Schrama, Erik (Shell) | Naughton-Rumbo, Robin (Shell Intl E&P Co) | van der Bas, Fred (Shell Intl E&P BV) | Norris, Mark Robert (Schlumberger) | Shaoul, Josef R. (StrataGen Delft Bv)


This paper describes the development of a tight gas reservoir in the Dutch sector of the Southern North Sea, using a horizontal well with 5 hydraulic fractures. The reservoir is tight (average permeability below 0.1 mD) and was discovered in 1986. The first development well was drilled as a long reach horizontal well in 1990, and completed with a cemented liner. The well was perforated and initial production was 0.2 mln Nm3/d after which the well quickly dropped below its liquid loading limit of 0.09 mln Nm3/d. The well was brought back into production 13 years later and produced at a stable rate of 0.07 mln Nm3/d. In 2005 the well was sidetracked using under-balanced drilling in an attempt to intersect natural fractures (Veeken, 2007). The initial production from this sidetrack was 0.1 mln Nm3/d, but this time the well was able to sustain production at 0.07 mln Nm3/d as the tubing head pressure was lower by that time.

To develop this reservoir, the well was sidetracked (overbalanced) in 2008 and completed with a cemented liner. In 2009, 5 hydraulic fractures were placed using a jackup support barge and a specially converted supply vessel. Since December 2009 the well has produced steadily at 0.3-0.4 mln Nm3/day, a (steady-state) production improvement factor of 5-6. This was the first true tight gas (<0.1 mD) development in the North Sea using a horizontal well with multiple fractures. The initial production takes place at constant rate and constant pressure, which suggests that significant cleanup is taking place, either in the fracture or the reservoir or both. An attempt has been made to model this cleanup in a 3D reservoir simulation model.

This paper describes the background of the project, fracture design methodology, operational issues and lessons learned, fracture treatment data analysis, post fracturing production analysis (with over a year of production history) and production forecast. This paper is a valuable case study for operators and contractors involved in offshore fracturing operations in low permeability gas reservoirs.

The field was discovered in 1986 by a deviated well which was fracced using a diesel based frac fluid. The production improvement factor (post compared to pre frac rates) was around 2.0, with the pre frac rate at 0.38 mln Nm3/d (at a 22 bar flowing tubinghead pressure (FTHP). In 1989 a deviated appraisal well was drilled which was fracced using a water based frac fluid. Prior to fracture stimulating the well did not produce, but after an acid stimulation it produced 0.05 mln Nm3/d at 22 bar FTHP. After fracture stimulation the well produced 0.28 mln Nm3/d at 22 bar FTHP.

In both wells, high net pressures were observed and there were indications of multiple fractures (partly due to well orientation and perforation interval length). Both wells suffered from severe wash outs in the reservoir, which could have led to the high net pressures. In the first well 50% of the frac fluids could be recovered in a period of 26 days. In the second well only 15% of the frac fluids were produced back.

In 1990, the first horizontal development well was drilled in the field. This was one of the first horizontal wells in the Dutch offshore sector. The well initially produced at 0.2 mln Nm3/d at 90 bar FTHP, but died quickly due to liquid loading after declining below 0.09 mln Nm3/d. The pressure built back up to original reservoir pressure when the well was closed in for an extended period. Production was resumed at lower FTHP at a stable 0.07 mln m3/d.