Abstract

BP in the U.K. North Sea attempted to drill a horizontal oil producer in the Harding field in 2006. Designed to produce an initial 10,000 blpd from 2000 feet of reservoir section before water break through, the well was compromised by the collapse of the lower hole due to chronic shale instability. This also resulted in the pre-drilled liner being stuck and set higher than initially planned. With less than 200 feet of reservoir sand exposed at the heel of the well (in close proximity to the water leg), the initial expectations were of 4,000 blpd. However the well was found to be badly impaired and produced 400 blpd. Although the well had been displaced to a carbonate based low solids oil based mud (LSOBM) prior to completion, a significant quantity of the barite weighted drilling system was still in the well.

The damaging mechanism was determined to be synthetic oil based mud compressed around the screen completion as well as the mud from the uncompleted horizontal lower hole being squeezed into the screens as the open hole gradually collapsed with time. A Coiled tubing (CT) intervention was carried out in late 2006 with solvents and multiple attempts with an acidic nano wash solvent system, this was not successful in restoring well productivity.

In 2007 BP chose to use an advanced chelate based barite/carbonate dissolver system behind a proprietary pre-flush system in an attempt to recover well productivity. Four operations have now been performed since September 2007 without CT, all as simple bull head operations. As a result of these treatments the well productivity (PI) has increased from 1.5 up to 12 blpd/psi. Current well rates are between 4000 to 6000 blpd depending on well stability and slugging caused by increasing water cuts.

Introduction To The Harding Field

The Harding Field, in Block 9/23b of the U.K. North Sea (Figure 1), consists of 2 main reservoirs (Central and South) developed with horizontal wells, and several satellite pools accessed via extended reach wells (Figure 2). The 2 main reservoirs currently contain 13 horizontal producers, 3 water injectors and in the central reservoir, a single gas injection well. Both main reservoirs are overlain by large gas caps so well location and production were carefully managed to minimize excessive gas production through gas coning. As aquifer support is negligible, the reservoir pressure is maintained via re-injection of the produced water supplemented by water from a shallow aquifer zone.

The South reservoir has excellent static properties but the fluid quality is less favourable. The wells are all located in the Balder Formation which is a massive homogeneous sandstone up to 150 feet thick. It is poorly consolidated, with an estimated permeability of 8 to 10 Darcies, porosities of 32 to 35%, and a net to gross (NTG) of 93 to 95%. However, the viscous oil (23 ° API, 5 centipoise) leads to unfavourable mobility ratios which tend to promote coning. The wells are operated with low drawdown's (typically less than 20 psi) to minimize water and gas coning. It was possible to achieve this and still produce at high rates due to the very high productivity of the wells, which was often in the range of 500 to 1,200 blpd/psi.

The Harding Field came on stream in April 1996 and the south reservoir was initially developed over a 2 year period with 3 horizontal producers and 1 horizontal water injector, all in the high quality NTG sand. Sidetracks of the original producers have occurred to improve reservoir recovery, the 3rd being the IS3 well which was drilled as a sidetrack from a multilateral producer which had watered out during late 2005. Multiple sidetracks of the IS3 well target eventually led to the well being named IS3x.

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