The Heidrun Field is located in the Haltenbanken area offshore Mid-Norway. The reservoir temperature is 85 - 88°C and the reservoir pressure is close to hydrostatic pressure, around 250 bar. Seawater injection is utilized to increase recovery and for pressure support. With Ba2+ levels averaging about 200ppm, downhole sulphate scale deposition caused by seawater injection has been identified. The field came on stream in 1995. Heidrun presents a particular challenging scaling environment due to the combination of high Ba2+ content, demand for environmental friendly chemicals, strong top-side emulsion tendency, limited hydrostatics and at times high draw down within the gravel packs. In addition, the high kaolinite content (20–30 %) in the reservoirs introduces the risk of fines mobilization leading to plugging within the gravel packs especially with the development of overflush fluids volumes used during squeeze treatments. Scale control started in November 1999 with regular squeeze treatments. However, initial squeezes suffered from short treatment life and evidence of fines related productivity decline.
Under a joint R&D program, a multi-functional additive was developed that enhanced inhibitor adsorption, provided clay stabilisation and a certain level of scale inhibition.
This paper presents both laboratory and field data to elucidate the mechanisms involved in extending squeeze life and clay fines stabilization with this additive.
The Heidrun Field has been described in several papers over the past years1,2,3,4,5 and only a short overview is given here. The field is located in the Haltenbanken area offshore Mid-Norway, and was discovered by Conoco in 1985. It has been producing since 1995 with Statoil as operator. License owners are Petoro (64,16 %), ConocoPhillips (18.29 %), Statoil (12.43 %) and Fortum Petroleum (5.12 %).
The hydrocarbons are present in three reservoirs of Jurassic age at depths around 2400 m TVD MSL. The reservoir temperatures are from 85 to 88°C and reservoir pressures are close to hydrostatic pressure, around 250 bar. Seawater injection is utilized to increase recovery and for pressure support. With Ba2+ levels ranging from 60 to 300 ppm, downhole sulphate scale deposition caused by seawater injection was identified in well A-28 in May 2000.
The reservoir sands are in general poorly consolidated and contain 20–30 % clay minerals, as shown in Table 1. Kaolinite is the dominant clay mineral and occurs commonly as pore fills and coatings, often packed as sub-rounded aggregates with poor crystal face development. Other type of clay minerals is mica and illite, which range from 5 to 10 %. Most of the producing wells have sand control devices installed (gravel pack or stand alone screen). Well productivity is high prior to water breakthrough. However, a rapid decline in productivity is noted after water breakthrough in perforated and gravel packed wells with prepacked sand screens that have been stimulated with mud acid/clay acid treatments. Water related productivity decline in open hole completed wells occurs at significantly higher water cuts.
Downhole scale control presents a particular sever challenge due to a combination of high Ba2+ concentration in the produced water, significant fines migration, demand for environmental friendly chemicals, strong top-side emulsion tendency, limited hydrostatics and at times high draw down within the gravel packs. Aqueous and non-aqueous squeeze treatments have been deployed on Heidrun since late 1999 to provide scale control. However, several wells have suffered productivity loss due to fines plugging in the gravel pack, which is believed to be caused by the overflush fluid volumes used during scale squeeze treatments.