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.

The formation of near well-bore scale can have detrimental impact on well production. Pore plugging, restriction in wellbore i.d. and perforation plugging due to scale deposition can sometimes remain undetected over prolonged periods especially when very low water production is evident. To overcome this uncertainty, workers in our industry usually rely solely on scale prediction models to identify the potential of scale occurring. However, rarely is this information utilized further to explicitly quantify the impact of scale deposition on well performance and updated in the reservoir model, allowing better field management to be applied.In general, historical work published on scale prediction analyses have concentrated on identifying the potential of scale formation based on water composition(s) and localized information such as pressure, temperature (thermodynamic), while more recent publications have attempted to capture the kinetics and fluid hydrodynamics involved.Whilst these predictions can be very useful, it remains a challenge to then use the data output to quantify the impact of scale on overall well performance explicitly. Additionally, limiting factors and uncertainties can exacerbate the problem further. Examples are:• Availability of multidisciplinary tools to capture the processes involved • Uncertainty in field data including hydraulic flow units • Uncertainty over which layers bear 'scaling water' • Presence of multiple source of formation damage (e.g. fines migration) • Presence of other factors that can impact well performance (e.g. liquid loading, lifting) • Near-wellbore / formation scaling need not be seen physically This paper presents an overview of a new simulation workflow development to capture the impact of scale formation by coupling the domains of chemistry and reservoir engineering. Reservoir, near wellbore and macro-scale simulation techniques were integrated to evaluate the impact of scale deposition on well performance during the production lifetime.From the concise simulation workflow developed, we show how scale has impacted production in two synthetic wells, and more importantly, to characterize the location of the depositing scale. Initial problems relating to uncertainties in flow unit description and identification of potential layers of water source are highlighted, and the solutions to overcome these uncertainties are discussed. Based on this information, the volume of scale deposited at specific locations are enumerated and converted to wellbore and formation skins. Over time, slow deposition of scale was shown to clog up sections of specific perforation intervals along the well length and near wellbore area. By reverse engineering, the explicit impact of scale deposition on well production over time was quantified.

The formation of near well-bore scale can have detrimental impact on well production. Pore plugging, restriction in wellbore i.d. and perforation plugging due to scale deposition can sometimes remain undetected over prolonged periods especially when very low water production is evident. To overcome this uncertainty, workers in our industry usually rely solely on scale prediction models to identify the potential of scale occurring. However, rarely is this information utilized further to explicitly quantify the impact of scale deposition on well performance and updated in the reservoir model, allowing better field management to be applied.In general, historical work published on scale prediction analyses have concentrated on identifying the potential of scale formation based on water composition(s) and localized information such as pressure, temperature (thermodynamic), while more recent publications have attempted to capture the kinetics and fluid hydrodynamics involved.Whilst these predictions can be very useful, it remains a challenge to then use the data output to quantify the impact of scale on overall well performance explicitly. Additionally, limiting factors and uncertainties can exacerbate the problem further. Examples are:• Availability of multidisciplinary tools to capture the processes involved • Uncertainty in field data including hydraulic flow units • Uncertainty over which layers bear 'scaling water' • Presence of multiple source of formation damage (e.g. fines migration) • Presence of other factors that can impact well performance (e.g. liquid loading, lifting) • Near-wellbore / formation scaling need not be seen physically This paper presents an overview of a new simulation workflow development to capture the impact of scale formation by coupling the domains of chemistry and reservoir engineering. Reservoir, near wellbore and macro-scale simulation techniques were integrated to evaluate the impact of scale deposition on well performance during the production lifetime.From the concise simulation workflow developed, we show how scale has impacted production in two synthetic wells, and more importantly, to characterize the location of the depositing scale. Initial problems relating to uncertainties in flow unit description and identification of potential layers of water source are highlighted, and the solutions to overcome these uncertainties are discussed. Based on this information, the volume of scale deposited at specific locations are enumerated and converted to wellbore and formation skins. Over time, slow deposition of scale was shown to clog up sections of specific perforation intervals along the well length and near wellbore area. By reverse engineering, the explicit impact of scale deposition on well production over time was quantified.