Controls on the Production Performance of fip3 of the North West Hutton Field, UK North Sea

Abstract

The North West Hutton Field was discovered in 1975 and is located in Block 211/27 in the East Shetland Basin, Northern North Sea around 80 miles NE of Shetland. It is a large oil field in the Brent Group, covering an area of 13440 acres and has a history of complex and variable well performance, significantly worse than the adjacent up dip Hutton field, despite both having the same Brent Group paralic sandstone reservoirs. North West Hutton was reported to contain 1157 mmBBL oil in place in 1983 and reserves were estimated at 273 mmBBL. It had initially high flow rates which rapidly declined, along with pressure. A water injection programme was implemented, despite this the recovery factor was only around 10%. This study focuses on fip3, otherwise known as the Eastern Sector of North West Hutton, where 12 production wells have been drilled, 3 of which were converted to water injection wells.
The study aims to determine controls on both instantaneous well rate and overall ultimate recovery per well in terms of reservoir architecture, reservoir quality and faulting in fip3. The study used a combination of wireline log and core data coupled with oil production, water production and water injection data on a per-well basis to evaluate field performance.
Laterally extensive and sheet like reservoir architecture such as the valley fill of the Etive Formation were indicated to have been flooded early on in the field’s production and the oil swept due to stratigraphic connectivity between wells. Water injection support was ineffective at sweeping sands above and below these. The rapid decline of oil rate was attributed to complex faulting, compartmentalisation and the highly permeable, but heterogenous, thin and poorly connected, fluvial channel sandbodies in the Ness Formation being quickly drained. This study has identified likely remaining oil in these sandbodies, particularly in compartmentalised areas, such as the west of fip3. There may be potential for redevelopment by focusing on these sandbodies in similarly compartmentalised reservoirs of a paralic nature which also suffered rapidly declining pressures. Existing reserves may be accessed using newer tried and tested technology which was not available or not applied in the original development. Tactics such as horizontal drilling or dramatically increasing the water oil ratio (WOR) should be addressed. Controls on the production performance of wells in fip3 were timing (earlier wells performed better due to higher pressures, oil not yet having been swept and had fewer operational issues that develop with time), rock quality (controlled by burial depth and facies), compartmentalisation and sandbody connectivity, pressure support, well spacing and operational issues. Many wells had poor well spacing in that they were drilled into existing flood fronts or too close to existing wells, restricting the expected ultimate recovery per producer. The study has indicated the potential for redevelopment in the south of fip3, where A14 previously had good performance and received good pressure support.