The Alba field in the central North Sea is an unconsolidated sandstone reservoir with an average permeability of around three darcies. Maximising productivity and extending completion life has been an evolving process throughout the life of this field. Recent practice is to drill the horizontal reservoir section using a water-based drill-in fluid (DIF) and complete with a circulating open-hole gravel pack (OHGP). One current option employs an oil-based DIF prior to gravel packing in brine. Both of these procedures have allowed higher off-take rates from these wells than previous completion practices.
New advances in the nature of delayed stimulation chemicals and the introduction of more effective additives (generating acid in situ downhole) made it of considerable interest to determine whether productivity could be further enhanced. One major obstacle to overcome was the uncertainty associated with the placement and uniform distribution of the stimulation treatment in a horizontal well, allowing the entire filter cake to be contacted and broken down successfully. This paper describes how the deployment problems were successfully circumvented.
A dual density treatment was employed in which both the upper and lower zones of the horizontal well-bore were targeted so that the filter cake on both the upper and lower surface in the hole would be contacted and attacked. Evidence will be provided indicating the placement resulted in an enhanced productivity index compared to conventional, non-stimulated completions. The new stimulation treatment was effective in wells drilled with either a water-based DIF or an oil-based DIF.
Introduction
The history of the development of the Alba field over theperiod from its inception until 2002 has been reported in previous publications.1,2 This paper reports recent developments.
The Alba oil field located in block 16/26 of the UK sector of the North Sea comprises an Eocene sandstone formation that is thin, highly porous, highly permeable, very unconsolidated and overlain by a bed of impermeable, highly reactive shale. The nature of the reservoir dictated that development would be best achieved by open hole completions and highly deviated or horizontal reservoir sections with the productive interval being sited near the top of the sand body. The earliest approach was to run screen only completions, initially using synthetic oil-based mud (OBM) as the drill in fluid (DIF), evolving through the same screen arrangements but using a saturated brine/sized sodium chloride based DIF. Both approaches provided excellent drilling properties but there were severe limitations in respect of productivity in the case of those wells drilled with synthetic-based mud (SBM) and screen longevity was a problem for the wells using the sized salt approach.1 Both issues were addressed by adopting a sized carbonate DIF and performing open hole gravel packs (OHGP) on the productive sections.
Since these observations on the evolution of the drill-in fluids and completion strategies on the Alba were reported, several other important developments have been made. In apparent contrast to the message provided in the earlier report2 about the robustness of the gravel pack completion philosophy relative to stand alone completions, the appearance of extremely early well failures on a few gravel packed wells have given cause for additional concern.
As previously reported, the well failure data indicated that the standalone screen completions had failure rates in the order of 70–90%, with failures typically occurring after one to three years of production. Open hole gravel packed wells, in contrast, at least initially, exhibited prolonged well life. Thirteen open hole gravel packs were successfully completed and on line before any incidence of failure.2 Subsequently, the field has experienced four well failures in a relatively short period of time. One of the wells in question produced for four years before failing but the other three failed after only a few weeks of production.
