A 3-week corrosion testing of UNS N06625 was conducted in supercritical fluid at 350°C and 10 bars. The aim of corrosion testing was to simulate high temperature geothermal environment i.e. IDDP-1 conditions where previous on-site corrosion testing of UNS N06625 and other alloys had been conducted. The simulated environment had lower concentration of H2S and CO2 in the steam comparing IDDP-1 environment. In addition, no silica scaling was precipitated on the samples nor HF was used in the simulated experiment. The corrosion rate was determined with weight loss comparison and the corrosion forms were analyzed with SEM, XEDS and light microscope. The result of the simulated experiment shows that some localized corrosion is occurring and the corrosion rate of UNS N06625 in simulated environment is similar to the corrosion rate observed in IDDP-1.
In the first deep drilled well (IDDP-1) in the Iceland Deep Drilling Project in-situ weight loss experiment was conducted from an exhaust pipe from wellhead of the borehole for several corrosion resistant alloys and carbon steel types. Superheated geothermal steam was obtained from the well with 450°C and 140 bars at wellhead. The weight loss experiments were done in exhaust pipe with throttled steam from the wellhead where the temperature was 350°C and pressure 12-13 bars . The geothermal fluid (see Table 1) from IDDP-1 contained corrosive components such as CO2 and H2S and additionally HCl and HF gases  Due to the pressure drop, large amount of silica precipitated in the exhaust pipeline and hence silica covered the corrosion samples during the testing. All the corrosion samples had very low corrosion rates i.e. the corrosion resistant alloys and generally low corrosion resistant carbon steel. The corrosion resistance of N06625 was measured to be less than 0.001 mm/year but localized cracks and pits were observed on sample after testing. From the corrosion testing, it was concluded that the silica scaling prevented general corrosion but promoted under deposit corrosion  of UNS N06625. Same was concluded from the results of the testing of other samples.
Ragnarsdottir, Kolbrun R. (Innovation Center Iceland) | Karlsdottir, Sigrun N. (University of Iceland) | Arnbjornsson, AÐalsteinn (Innovation Center Iceland) | Haraldsdottir, Helen O. (Innovation Center Iceland)
Geothermal steam commonly contains CO2 and H2S dissolved gases which are corrosive substances. An explosive welding technique was used for preparing samples of clad carbon steel material with different corrosion resistant alloys (CRAs) for testing in geothermal environment. A test unit was connected to a high temperature geothermal well, KJ-34, at the Krafla geothermal system in Iceland for in-situ corrosion testing. The steam was around 190°C with 14 bar pressure, pH value 8.57 and contained dissolved gases, including H2S and CO2. For this preliminary experiment austenitic stainless steel, S31254, and Hastelloy, N10276, were clad on low carbon steel plates with explosive welding for testing in geothermal environment. This pre-test was performed in order to examine the performance of the materials and explore the possibility of protecting the un-clad sides of the samples from the steam by coating them with ceramic paint. This paper reports the results from the tests and inspection of the CRA clad material including visual inspection, microstructural and chemical composition analysis with SEM and XEDS.
The geothermal industry is rapidly growing worldwide due to geothermal energy being considered more environmentally friendly than fossil fuel based energy sources. However, geothermal steam utilization technology has not yet reached maturity and a number of problems have yet to be solved. One of these problems is cost effective material selection. Corrosion resistant (CRA) alloys are very expensive and lack strength compared to low carbon steel pipe material that is commonly used in the geothermal industry. Therefore, the need for cladding low carbon steel pipes with CRA alloys has increased. One of these solutions is explosive welded clad materials as a method of fabrication of new corrosion resistant coatings as an innovative technique that produces material systems with unique properties. Therefore, development of corrosion resistant clad materials would extend the service life of geothermal plants and also reduce the need for expensive corrosion resistant bulk materials. Coupon test was performed at the Krafla geothermal power plant to evaluate corrosion resistance of the tested materials and examine whether the welding process affected the material.
Corrosion behavior in geothermal steam of CoCrFeNiMo high entropy alloy Ioana CSÁKI University Politehnica Bucharest Splaiul Independentei 313 Bucharest 060042, Romania Sigrun Nanna KARLSDOTTIR University of Iceland Hjardarhagi 2-6 Reykjavík, IS-107 Iceland Radu STEFANOIU University Politehnica Bucharest Splaiul Independentei 313 Bucharest 060042, Romania Laura Elena GEAMBAZU University Politehnica Bucharest Splaiul Independentei 313 Bucharest 060042, Romania ABSTRACT A multicomponent High Entropy Alloy (HEA) CoCrFeNiMo processed with vacuum arc remelting procedure was tested for corrosion in geothermal environment in the Reykjanes Geothermal Power Plant in Iceland. Microstructural and chemical composition analysis of the material was performed before and after testing in the geothermal steam with an electron scanning microscope (SEM) and X-ray Energy Dispersive Spectroscopy (X-EDS). A weight loss method was also used to measure the corrosion rate of the CoCrFeNiMo high entropy alloy. The results showed that the uniform corrosion rate low, on average 0.0001mm/year. And inspection of the specimen after the exposure in the geothermal environment revealed corrosion products contains sulfur and oxygen.
The IDDP-1 well was the hottest flowing geothermal well in the world producing 450 °C and 140 bar superheated steam. The IDDP-1 steam contained dissolved gases, H2S, CO2, H2, HCl and HF, which upon condensation became highly corrosive. Unfortunately, the well had to be closed after several months of discharging to due to failure in the master valves after leakage occurred in sampling valves due to corrosion. After shut-down small fragmented steel samples were retrieved from the well during down-hole camera inspection. Microstructural and chemical composition analyses were done on the samples with SEM and XEDS. The result showed that the samples have extensive corrosion damage, in the form of corrosion pits and internal micro-cracks and fissures. These are filled with corrosion products and are parallel to the surface. The chemical composition and microstructural analysis of the steel fragments indicate that they are from the API K55 carbon steel production casing of the IDDP-1 well. The corrosion damage was present deep into the material. The samples were etched for metallurgical analysis which revealed disappearance of pearlite close to the micro-cracks and fissure. High Temperature Hydrogen Attack (HTHA) is believed to be the cause of the decarburization of the steel and the corrosion damage of the samples.
After the IDDP-1 well was closed and killed with cold water injection due to failure in the master valves the well was inspected with camera down-hole for damages of the casings. Three failures where revealed from a video log of the well that shows the production casing ruptured at approximate depths of 300 m, 356 m and 505 m1. These failures occurred at joints where the casing had been pulled down, teared from the coupling, presumably due to tension from thermal contraction2. Also during the initial flow testing of the well, the production casing collapsed at around 620 m depth, causing it to fall inward and partially block the well. During the inspection of the well after the quenching, it became apparent that the leakage occurred through all the casings at 620 m depth. During inspections of the well downhole with camera after shut down small steel fragments were retrieved. Inspection of corrosion damage with visual inspection and microstructural and chemical composition analysis of the steel fragments is described in this paper.
ABSTRACTIn recent years there has been an increased interest in drilling deeper geothermal wells to obtain more energy output per well with the corresponding higher temperature and pressure and increased corrosiveness of the geothermal environment. To explore the potential of the high alloy austenitic stainless steel UNS S31254 in future deep geothermal wells corrosion testing was done in simulated geothermal environment at 180°C and 350°C with a pressure of 10 bar. The simulated environment was composed of steam with H2S, HCl and CO2 gases, with a pH of 3 upon condensation. The testing was done in a flow through reactor for 1 and 3 week exposures. The stainless steel UNS S31254 performed well at 180°C with negligible corrosion rates both for the 1 and 3 week tests and no localized corrosion damage detected. After the testing at 350°C localized corrosion and substantial amount of NaCl crystals were observed on the surface of the samples. Microstructural and chemical composition analysis revealed large cracks in the cross-section of the sample most likely due to chloride induced stress corrosion cracking. The measured corrosion rate for the 1 and 3 week test was 0.024 mm/year and 0.24 mm/year respectively.INTRODUCTIONMaterials used in high temperature geothermal steam can be subjected to corrosion due to the chemical composition of the geothermal fluid. Geothermal fluids contain corrosive substances such as the dissolved gases hydrogen sulfide (H2S) and carbon dioxide (CO2), and chloride ions (Cl-)1-5. The source of chloride ions (Cl-) can be from volatile chloride transported as hydrochloric acid (HCl) in the gas phase from the volcanic system or from salt brine in geothermal areas close to the sea. If localized enrichment of hydrochloric (HCl) acid occurs e.g. due to condensation and/or re-boiling it will cause severe corrosion of materials in the systems6-7. H2S in wet environment, such as in geothermal environment, can also cause severe corrosion damage in materials exposed to the environment, including hydrogen induced cracking (HIC), stress corrosion cracking (SCC) and sulfide stress cracking (SSC)8-14.
Ragnarsdottir, Kolbrun R. (Innovation Center Iceland) | Karlsdottir, Sigrun N. (University of Iceland) | Leosson, Kristjan (Innovation Center Iceland) | Arnbjornsson, Aðalsteinn (Innovation Center Iceland) | Guðlaugsson, Sæmundur (ON Power) | Haraldsdottir, Helen Osk (Innovation Center Iceland) | Buzaianu, Aurelian (METAV- R&D) | Csaki, Ioana (“Politehnica” University) | Popescu, Gabriela (“Politehnica” University)
ABSTRACTDevelopment is needed for new materials and technology to extend the life and reliability of material surfaces used in geothermal steam turbines. A test unit was designed so that steam flows directly from the wellhead into the test unit through a nozzle where the steam is flashed at high velocity on the target area. This setup simulates the effect of erosion and erosion-corrosion in geothermal steam turbines in Iceland. Well HE-29 at Hellisheiði geothermal power plant was selected for testing. The steam from the wellhead had temperatures around 210°C at 18 bar pressure and it contained dissolved gases, including H2S and CO2. In the preliminary experiment 12 low carbon steel plates were coated with different spraying methods and materials to obtain protective layers with improved erosion-corrosion resistance for geothermal turbine environment. The experiments will explore which of the tested spraying methods and materials are the most suitable for this application. This paper reports the first results from the tests and inspection of the coatings on the low carbon steel including; visual inspection, microstructural and chemical composition analysis with SEM and XEDS.INTRODUCTIONThe geothermal industry is rapidly growing worldwide due to geothermal energy being considered more environmentally friendly than fossil fuel based energy sources. However, geothermal steam utilization technology has not yet reached maturity and a number of problems have still not been solved. One of these problems is wear and erosion corrosion in turbines. This extends to both turbine blades and rotors which are the subject of this paper. The aim is to develop a new design for a material surface (coating) for steam turbines to be able to extend their lifetime and reliability. Thermal spraying processes and multi composite technology will be applied to enhance surface performance of turbine steel components. New coated surfaces will be tested and compared with steel material being used today. The new coating materials are designed to withstand corrosive geothermal environments and to protect different parts of a turbine. This applies particularly to damages caused by erosion, corrosion fatigue and stress corrosion cracking (SCC). Well HE-29 at Hellisheiði Power Plant in Iceland was selected for testing with temperatures around 210°C at the wellhead and pressures around 18 bar. The steam velocity was around 31 m/s and the pH value was 8.24. The steam contains non-condensable gases such as hydrogen sulfide (H2S) and carbon dioxide (CO2). Concentration of CO2 in the Hellisheiði area is similar or lower to its concentration in other high temperature geothermal systems in Iceland. It is hypothesized that the cause is insufficient supply of this gas to the fluid to saturate it with calcite.1 The Hellisheiði geothermal field is located in the Hengill area. The Hengill geothermal system is located in southwest of Iceland on the Mid-Atlantic Ridge and consists of two geothermal power plants; the Nesjavellir and Hellisheiði power plants. The Hellisheiði geothermal system is composed of layers of basaltic hyaloclastites and other rock types, that are located within the Hengill central volcano where the volcanism is most intense.2-3
Csaki, loana (University Politehnica Bucharest) | Manea, Ciprian Alexandru (University Politehnica Bucharest) | Trusca, Roxana (University Politehnica Bucharest) | Karlsdottir, Sigrun Nanna (University of Iceland) | Stefanoiu, Radu (University Politehnica Bucharest) | Geanta, Victor (University Politehnica Bucharest)
ABSTRACTA multicomponent High Entropy Alloy (HEA) AlCrFeNiMn processed with vacuum arc remelting procedure was tested for corrosion in geothermal environment in the Reykjanes Geothermal Power Plant in Iceland. Microstructural and chemical composition analysis of the material was performed before and after testing in the geothermal steam with an electron scanning microscope (SEM) and X-ray Energy Dispersive Spectroscopy (X-EDS). A weight loss method was also used to measure the corrosion rate of the AlCrFeNiMn high entropy alloy. The results showed that the uniform corrosion rate was quite high, on average 3 mm/year. Microstructural and chemical composition analyses of the specimen after the exposure in the geothermal environment revealed corrosion products, containing sulfur and oxygen. The high corrosion rate suggests the AlCrFeNiMn would not be suitable for coating layer for geothermal component.INTRODUCTIONGeothermal industry worldwide is facing two challenging problems directly associated to the chemical composition of the geothermal steam; scaling and corrosion. Scaling is the precipitation of solids due to oversaturation or redox reaction in the processed geothermal brine. Corrosion of construction materials is another great concern generally arises from the combination of elevated temperature and corrosive key species in geothermal brine and steam1.The geothermal steam contains dissolved gases, such as carbon dioxide (CO2) and hydrogen sulfide (H2S). In some geothermal systems chloride ions2 - 4 are also present. The source of the chloride ions (Cl-) can be from salt brine in geothermal areas close to the sea or volatile chloride transported as hydrogen chloride (HCl) gas from the volcanic system5, 6. Corrosion in geothermal systems is dependent on operational factors such as the pressure, temperature, flow rate and the pH level of the liquid at the point of production7. Geothermal steam also contains dissolved minerals that can precipitate from the liquid and deposit onto the surface of equipment and in geothermal well casings and cause erosion problems. The scaling occurs because of change in pressure, temperature or pH value of the liquid which disturbs the equilibrium of the system8 - 10. Scaling and corrosion can lead to operational problems and damages of geothermal turbines and its components due to erosion- corrosion which can lead to high costs associated with maintenance, materials cost and loss of power production11 - 14.
Geothermal power plants are considered to be environmentally attractive because with them renewable energy source can be utilized. But geothermal steam contains non-condensable gases (NCG) such as carbon dioxide (CO2) and hydrogen sulfide (H2S) which may cause environmental, safety and health problems if they are not disposed correctly. H2S emission from power plants in Iceland has now become a problem due to new stricter legislation in Iceland regarding air quality. Recently Icelandic power companies started re-injecting H2S and CO2 back into the ground in a research project called SulFix to decrease H2S emission from Icelandic geothermal power plants. The gases are dissolved in condensate at 25§C and 5 bars in a newly constructed H2S abatement system, air-cleaning station, at Hellisheiði geothermal power plant in Iceland. In this study the corrosion behavior UNS S31603, chosen for the absorption tower in the H2S cleaning process, was investigated as well as other materials for comparison. Corrosion experiments were done over two time periods, 4 weeks and 12 weeks. The specimens were installed into the absorption tower where the H2S and CO2 gases were separated from other NCG and dissolved in condensate. The susceptibility to stress corrosion cracking (SCC) of the stainless steel UNS S31603 was investigated and corrosion rates were calculated for the carbon steel S235, and the stainless steels UNS S31603 and UNS S31803 for the two time periods. The results showed that the material selection for the absorption tower seems to be sufficient; UNS S31603 showed no signs of corrosion damage. The UNS S31803 duplex stainless steel was also not effected by corrosion during the testing. On the other hand, the carbon steel S235 was severely damaged by hydrogen induced cracking (HIC) and high corrosion rate, well above the acceptable limit of 0.1 mm/year.
Karlsdottir, Sigrun N. (University of Iceland) | Thorbjornsson, Ingolfur O. (Reykjavik University) | Ragnarsdottir, Kolbrun R. (Innovation Center Iceland ) | Einarsson, Asbjorn (Asbjorn Einarsson Consultants)
The IDDP-1 well in the Krafla geothermal field in Iceland is the first well in the Icelandic deep drilling project. The superheated steam from the well is extremely hot (450°C) with a 120 bar pressure at the wellhead. The IDDP-1 steam contains acid gas and is highly corrosive when it condenses. A test unit with eight different material types of heat exchanger tubes was set up in order to investigate the possibility of using the IDDP-1 steam directly for heat exchangers without prior removal of silica, sulfur and acid gases. The tube materials were three types of stainless steel, two titanium alloys, and two nickel alloys. In addition one carbon steel tube was added as a reference. The inlet temperature and pressure were 330-350°C and 52-62 bar. The steam condensed in the tubes with an outlet temperature of about 270°C. Severe problems were encountered in the use of steam traps at the outlet end of the tubes due to clogging of silica and they had to be replaced with orifice plates. This paper reports the results from the testing and inspection of the pipes including visual inspection, and microstructural and chemical composition analysis with SEM with XEDS.
However, with ingress of oxygen, due to contamination of fresh water as an example, the corrosion rate can increase significantly. In order to establish methods of monitoring corrosion under these conditions, several corrosion monitoring methods were tested in two locations in Reykjavik, Iceland and one location in Keflavik, Iceland. It was found that electrochemical tests tended to overestimate the corrosion rate due to the slow polarization behavior of the system, while weight loss techniques required too long of an exposure to provide real-time information; although they gave reliable historical data on the corrosion that had accumulated over the previous three, six or twelve months' time. A differential ERprobe proved to be the most promising measurement technique for these conditions. The analysis of the corrosion products using EDS and XRD further disproved the common notion that the low corrosion rate found in the geothermal water was due to the formation of a protective iron sulfide film. No iron sulfide film was detected, but with the ingress of oxygen, a thick magnetite film was detected. The low corrosion rate is therefore due to the favorable water chemistry, which leaves the carbon steel pipe surface vulnerable to corrosion if it is exposed to an oxidant. Key words: geothermal, low-conductivity corrosion, corrosion monitoring, hydrogen sulfide INTRODUCTION Geothermal energy accounted for 90 % of the energy used for space heating in Iceland in 2011.