corrosive species and scaling in wells at olkaria ... - Orkustofnun

1. INTRODUCTION
For many countries geothermal energy is an important resource. Utilisation, both direct and for power
generation, is increasing faster than that of any other energy resource. Worldwide installed capacity of
geothermal power plants has increased by ~ 10 % or more per year over the last two decades (Bertini,
2005). The technology needed to harness geothermal energy has advanced much over the last 20-30
years and steps have been taken to reduce the environmental impact of geothermal energy utilization,
particularly by injection of spent fluid into wells and directional drilling. The main operational
problems encountered when utilising high-temperature geothermal reservoirs for power generation
involve the formation of various types of scales in production wells, surface equipment and injection
wells. Corrosion is sometimes also a problem, both for high and low-temperature fluid utilisation.
The most common scales formed are amorphous silica and calcite. However, many other types of
scales have been encountered including metal-sulphides, silicates of iron and aluminium and
anhydrite. In geothermal fluids various species can be corrosive and these include chlorides, carbon
dioxide, ammonia, hydrogen ion, dissolved oxygen, bisulphate, which dissociates into sulphate and H +
upon cooling. Chloride ion breaks passive films that are protective on metal surfaces and can
concentrate in crevices and cause pitting corrosion. Hydrogen chloride in steam can produce acid
condensate and lead to severe corrosion. Dissolved carbon dioxide gas in geothermal water causes
corrosion of low carbon steels, which is generally localized.
In this study special attention is given to assessing the conditions for the formation of amorphous silica
and calcite scales, and the concentrations of the corrosive species CO 2 and HCl in geothermal water
and steam. Special attention is given to scaling in wells and wellhead equipment that are in contact
with slightly wet steam. The study is based on data from Olkaria, Kenya and Reykjanes, Svartsengi
and Nesjavellir, Iceland. Further scaling tests were carried out at Nesjavellir, Iceland, both at
wellheads and downstream, where the separated water was oversaturated with respect to amorphous
silica.
1.1 Corrosion in geothermal environments
Corrosive attack in high-temperature geothermal installations is found mainly in well casings,
condensate injection pipelines made of carbon steel, wellhead equipment and turbine blades. In
generation of electricity by direct contact condensing turbines where a cooling water circuit is utilized,
low pH (4-5) of the condensate is caused by the dissolution of CO 2 and H 2 S gases present in the steam.
In condensate injection pipelines made of carbon steel, Villa et al. (2001) and Villa and Salonga
(2000) report rapid deterioration due to low pH of condensates. Oxygen ingress exacerbates the
problem. When conductive heat losses occur along steam pipelines, steam may condense and through
dissolution of CO 2 and H 2 S, lower the pH (Thain et al., 1981; Henley et al., 1984). In Olkaria,
Svartsengi and Nesjavellir direct contact condensing turbines are utilized and low pH condensates
which are corrosive develop. Corrosion related to the low pH condensates on disposal is not reported.
In superheated steam where HCl is present Allegrini and Benvenuti (1970), Meeker and Haizlip
(1990) and Truesdell (1991) describe severe corrosion in well casings, steam gathering systems and
turbine blades, mainly caused by H + and Cl - . Thόrhallsson (2005) reported corrosion in steam
pipelines due to HCl transported in the steam in a dry steam well at Svartsengi. In Svartsengi,
Thórólfsson (2005) has reported various corrosion related problems observed during maintenance of
the plant.
Corrosion of casing in high-temperature geothermal systems can also be related to low pH associated
with acid-sulphate waters. In andesitic geothermal systems like those found in the Philippines, e.g. the
Tiwi and Bacman fields, Sugiaman et al. (2004) and Rosell and Ramos (1998) report casing corrosion
observed due to penetration by low pH acid sulphate water. Similar casing corrosion was reported in
Cerro Prieto, Mexico by Dominquiz (1980) and Miravalles, Costa Rica by Moya et al. (2005). In
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