Downhole Scale Management on the Alba Field: A Case History
Authors: Strachan Alistair , Stanley Rachel Elizabeth , Farrell Roderick , Dahle Smith Haakon , Leontieff Andre , Muir Jim 
Published: May 2013

The Alba field is located in Block 16/26 on the UK continental shelf. It has been producing hydrocarbons since 1994 from a loosely consolidated sandstone reservoir. As the field has aged, seawater injection has been used as pressure support and consequently the Alba reservoir sits in a mild barite produced water scaling regime.

In the early stages of seawater breakthrough the near well bore was protected from scaling by the use of a PMPA (phosphono-methylated polyamine) based scale squeeze inhibitor, offering fit for purpose performance and squeeze lifetimes. However, flow back from squeeze applications had to be carefully managed. As part of a scale management programme implementation, new sulphonated copolymer squeeze chemistry was applied downhole. This chemistry was further developed and characterized in terms of field performance and analytical detection.

In the last 10 years the Alba co-venturers have developed the Extreme South field, which is tied back to the Alba platform via a subsea line. This resulted in commingled flow on the platform and need for differentiated residual scale inhibitor detection. As part of a continuous improvement project Baker Hughes have developed a next generation tagged inhibitor, enabling residual detection of sulphonated copolymer chemistry via Inductively Coupled Plasma, down to very low inhibitor levels. This chemistry has been successfully utilised on the Extreme South wells.

This paper will discuss how the use of a comprehensive scale management programme coupled with Research and Development has contributed to both cost savings and value creation for the Alba co-venturers and added value for Baker Hughes. This can be quantified in terms of reduced deferment losses, resolution of detection issues, squeeze life improvements and prioritisation and elimination of unnecessary inhibitor applications.

Introduction

The Alba field overlies the Mesozoic Witch Ground Graben, south of the Fladen Ground Spur and north of the Renee Ridge. The field was discovered by the well 16/26–5 in 1984 and first oil was produced in late 1994.

The field is approximately 7.5 miles long by 1 mile wide, trends from NW to SE and comprises three parts: the main field, the 15-area and the 12-area. The reservoir is of earliest Late Eocene age and consists of a series of stacked high-density turbidite sands that are unconsolidated in nature and have been deposited within a pre-cut channel on an intra-slope terrace. Intra-reservoir shales occur throughout the field. They show reworked palaeontological signatures derived from pre-reservoir strata beyond the pre-cut channel. These shales are commonly below seismic resolution. The Alba reservoir typically has a porosity of 35% and permeability numbers in the range of 3 Darcys.

The reservoir is tilted with its highest point of the top structure occurring at the northern end of the field at a depth of approximately 6,080 ft and at the southern end at a depth of 6,560 ft. The water-oil contact is at 6,465ft. The underlying aquifer is shallowest at the northern end and most extensive at the southern end.

The Alba platform was installed as a minimum facilities module in the north of the field exporting oil to a floating storage unit (FSU). The FSU provides storage and final dehydration of sales crude prior to final export following transfer to shuttle tanker.

Oil production in the field is currently conducted through 25 horizontal producers and reservoir support is provided by sea water injection through 5 injectors, including a sub-sea injection manifold. Due to the unconsolidated nature of the reservoir, producers are completed with pre-packed gravel screens.