Summary Barium sulfate scale deposition in the near wellbore, perforations, or production tubing has severely affected well productivity in many North Sea Fields. This is due to the co-mingling of the sulfate-rich seawater used for reservoir sweep with formation water containing high concentrations of barium ions. Mitigation of this problem is generally achieved by regular "squeeze" deployment of scale inhibitor chemicals which retard scale precipitate formation and deposition. However, in some instances, the scale inhibitor is poorly retained within the reservoir rock matrix and short squeeze lifetimes are experienced. The net result in these cases is frequent well interventions which impact on both well productivity and field profitability. To solve this problem, a scale squeeze enhancer has been developed which acts to enhance retention and subsequent release of scale inhibitor in the reservoir. The first field deployment of this technology was in BP's Magnus asset. The trial demonstrated a more than doubling of the squeeze lifetime of an adsorption chemical. Introduction Magnus Field History. The Magnus oil field lies approximately 160 km north east of the Shetland Islands in the U.K. Sector of the North Sea. The field is located in blocks 211/7a and 211/12a, and is producing through the most northerly platform on the UKCS. The Magnus oil field was discovered by BP in 1974 and first production commenced in August 1983, reaching a peak annual average production rate of 144,301 stb/day in 1994. Reservoir Description. The Magnus field is divided into three producing intervals, the Turonian Reworked Sandstone, which overlays the Magnus Sandstone Member (MSM), which overlays the Lower Kimmeridge Clay Formation. The producing interval initially contained an estimated volume of 1650 mm/stb of oil in place. The MSM lies at a subsea depth of approximately 3000 m and is currently the main producing formation, having originally held 77% of the initial oil in place. The MSM is the most well defined of the Magnus formations, and can be broken down into several discrete sandstone zones or lobes, separated by shale mudstone units, which act as vertical permeability barriers. The typical MSM permeability is in the range 200 to 500 mD, with an average porosity of 21% and a maximum net pay of 108 m. Reservoir Management. The Magnus reservoir is currently being drained by 15 producing wells, while nine further wells, including three subsea tie-ins, are injecting seawater to support the reservoir pressure. However, off-take from the field to date has exceeded the volume injected, resulting in a significant drop in reservoir pressure from an original value of 6,650 psi to a current average of approximately 3,000 psi. In addition, a significant pressure gradient exists across the field, with a maximum of 7,500 psi observed in certain injectors, compared with 2,750 psi measured in several crestal producers. The field is now produced on a voidage replacement basis, however, significant differential pressure exists between lobes as a result of divergent pressure depletion through the MSM. Nature of Scale Problem. An analysis of the ionic composition of the formation waters produced from the various lobes or zones reveals subtle differences in their chemistry; however, in each case the produced water has a salinity almost identical to sea water. In addition, the barium concentration in Magnus formation water is in the range 160 to 220 mg/l. This combination of relatively low salinity and moderate barium loading creates a particularly harsh scaling problem.1 The scale problem is further complicated by the high production rates and relatively low well inventory available from the platform.1 In order to provide high oil rates, several of the Magnus production wells were perforated in multiple lobes to access the oil zones more efficiently. This results in the coproduction of waters with differing chemistry which, if left uninhibited, may lead to a rapid buildup of scale. The deposition of scale within the wellbore can lead to loss in productivity and interfere with the correct operation of subsea safety valves. Inhibition of the scale is, therefore, essential. The average scale inhibition treatment on Magnus, until 1997, protected approximately 300,000 to 800,000 barrels of produced water. However, as many Magnus wells now have high water cuts and, hence, high produced water rates, these treatments have often only lasted between 50 and 60 days. This is clearly unacceptable. In an attempt to improve squeeze life, a wide range of inhibitor chemistries have been evaluated and subsequently deployed on Magnus, including polyacrylates, sulfonated polymers, and a modified polyacrylate-based ter-polymer. These chemicals have been deployed mainly in adsorption-type treatments, although conventional precipitation squeezes have also been formulated and applied in the field. The most effective chemistry evaluated to date has been a modified acrylic acid/maleic acid copolymer. However, short squeeze lifetimes have still been experienced using this chemical. Enhancing Scale Inhibitor Retention. Scale inhibitors injected into the near-well bore region of an oil reservoir can be retained via an adsorption-only process, termed an adsorption squeeze, or a combination of adsorption and precipitation, termed a precipitation or phase separation squeeze.2–5 The selection of the type of squeeze treatment (adsorption or precipitation) is dependent on the physical characteristics of the target well (porosity, temperature, lithology, water production rates, etc.) and the water chemistry.6–8

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A common problem with gas lifted wells is the development, over time, of instabilities in the injection/production behaviour. The question raised is initially that of “probable cause and effect”; the understanding of which is essential to the determination of possible remedial action. The major causes of unstable behaviour fall into three broad categories: • Design related - the original design is inappropriate or inflexible. • Mechanical - damage to, and/or failure of, valves and equipment. • Dynamic flow behaviour - changes in fluid composition and/or phase changes. Commonly, the instability incorporates elements from more than one category. This paper discusses one case in which a horizontal well in the North Sea, which had a gas lift completion designed for operation at a water cut of around 20%, exhibited unstable production after a rapid rise in water cut to approximately 80%. The paper shows how a new and unique dynamic gas lift simulator was used to reproduce the observed well behaviour, and how the model was then used to recommend remedial action to stabilise production. The impact of these remedial actions is discussed in the context of the overall production management. Finally, the implementation of the recommendations and the subsequent well behaviour are presented.

Barium Sulfate scale deposition in the near-well-bore, perforations or production tubing has severely affected well productivity in many North Sea Fields. This is due to the commingling of the sulfate-rich seawater used for reservoir sweep with formation water containing high concentrations of barium ions. Mitigation of this problem is generally achieved by regular 'squeeze' deployment of scale inhibitor chemicals which retard scale precipitate formation and deposition. In the squeeze procedure, scale inhibitor is injected several feet radially into the production well where it is retained by adsorption and/or formation of a sparingly soluble precipitate. The inhibitor slowly leaches into the produced water over a period of time and protects the well from scale deposition. However, in some instances, the scale inhibitor is poorly retained within the reservoir rock matrix and short squeeze lifetimes are experienced. The net result in these cases is frequent well interventions which impact on both well productivity and field profitability. To solve this problem, a scale squeeze enhancer has been developed (jointly by BP Exploration and BP Chemicals) which acts to enhance retention and subsequent release of scale inhibitor in the reservoir. The first field deployment of this technology was in BP's Magnus asset. The trial demonstrated a more than doubling of the squeeze lifetime of an adsorption chemical and has subsequently led to considerable cost savings for the Magnus asset by reducing well intervention frequency and subsequent well downtime. Introduction Magnus Field History. The Magnus oilfield lies approximately 160 km north east of the Shetland Islands in the UK Sector of the North Sea. The field is located in blocks 211/7a and 211/12a, and is producing through the most northerly platform on the UKCS. The Magnus oilfield was discovered by BP in 1974 and first production commenced in August 1983, reaching a peak annual average production rate of 144,301 stb/day in 1994. Reservoir Description. The Magnus field is divided into three producing intervals, the Turonian Reworked Sandstone, which overlays the Magnus Sandstone Member (MSM), which overlays the Lower Kimmeridge Clay Formation. The producing interval initially contained an estimated volume of 1,650 mmstb of oil in place. The MSM lies at a sub-sea depth of approximately 3000m and is currently the main producing formation, having originally held 77% of the initial oil in place. The MSM is the most well defined of the Magnus formations, and can be broken down into several discrete sandstone zones or lobes, separated by shale mudstone units, which act as vertical permeability barriers. The typical MSM permeability is in the range 200–500 mD, with an average porosity of 21% and a maximum net pay of 108 m. Reservoir Management. The Magnus reservoir is currently being drained by 15 producing wells, while 9 further wells, including 3 sub-sea tie-ins, are injecting seawater to support the reservoir pressure. However, off-take from the field to date has exceeded the volume injected, resulting in a significant drop in reservoir pressure from an original value of 6650 psi to a current average of approximately 3000 psi. In addition, a significant pressure gradient exists across the field, with a maximum of 7500 psi observed in certain injectors, compared with 2750 psi measured in several crestal producers. The field is now produced on a voidage replacement basis, however, significant differential pressure exists between lobes as a result of divergent pressure depletion through the MSM. Nature of Scale Problem. An analysis of the ionic composition of the formation waters produced from the various lobes or zones reveals subtle differences in their chemistry; however, in each case the produced water has a salinity almost identical to sea water. In addition, the barium concentration in Magnus formation water is in the range 160–220 mg/l. P. 161^