PERFORM - Geothermal Corrosion and Scaling Well Check

Welcome to the interactive PERFORM corrosion and scaling guidelines web-app. By providing information about your well's construction, performance, and brine composition, the app will guide you through the identification of the types of issues that could occur within your well and their severity, a comparison of your well to others in our open database, and will provide methods that could mitigate the potential issues.

Please select from the dropdown menu below whether you would like to complete the check for corrosion or scaling.

Corrosion well check

In geothermal wells, corrosion is an often occuring issue that can severely impact the integrity and performance of the doublet. Corrosion is primarily caused by oxygen ingress into the brine (resulting from air infiltrating topside equipment or tubing connections), or the presence of lead ions and/or CO2 in the brine (coming from the reservoir). Corrosion mainly affects the well's tubing, as well as topside equipment (such as the heat exchanger). Corrosion mainly impact a well's productivity through the release of rust particles, which can cause plugging of the injection wells, reducing injectivity.

Mechanisms of corrosion come in many different forms; uniform, pitting, galvanic, etc. What type is the dominant contributor to corrosion in any given well depends on a number of factors, including tubing and equipment materials and the interfaces between them, corrosion drivers and brine chemistry, and well design and geometry. By providing inputs to the questions in the short questionnaire below, a general indication can be provided of the corrosion types that might occur within your well. Later in this well check, advice on mitigation strategies for the different corrosion mechanism will be provided.

Please indicate below which materials make up a significant portion of the tubing or equipment walls.

Please indicate whether the brine in your well contains large concentration of any of the following:

Are there parts in your well where dissimilar metals come into contact with each other, whilst having a liquid connection between them? For example when a section of carbon steel tubing transitions into a section of stainless steel tubing?

Does your well's design feature sharp changes in flow direction, or sudden variations in tubing diameters?

Thanks for answering the questions! Click the button below to get a list of the corossion types that are most likely to occur in your well. Click any of the listed corrosion types to show additional information on it.

Uniform corrosion is only possible for carbon steel in the brine solution. Several cathode reactions may facilitate this reaction including oxygen reduction and hydrogen reduction. High flow conditions or elevated temperature conditions may favour rapid corrosion in some areas while other areas may be partly covered by rust products (iron oxide), slowing down the process here.

Pitting corrosion is mainly a problem for CRAs that are protected by a passive oxide layer. Even trace levels of oxygen may cause pitting, especially for low alloy grades like 17Cr or EN 1.4401 stainless steel. Corrosion becomes very localised in the pit because the majority of the surface remains passive, at the same time facilitating the cathode reaction. Moreover, the metal-rich and low-pH solution formed in the pit makes the corrosion self-catalytic.

If stainless steel components are coupled to carbon steel, no corrosion will take place because the less noble carbon steel provides cathodic protection at the cost of faster corrosion of this steel. Thus, the risk of severe pitting is only relevant if larger sections of stainless steel (pipework, heat exchangers or pumps) are in-stalled. This is also the reason why highly resistant titanium is used in the plate heat exchangers.

Pitting corrosion and localised corrosion may also occur on carbon steel, if the steel is partly covered by electrically conductive scales such as iron sulphide.

Crevice corrosion have many similarities with pitting, because it is promoted by an oxygen concentration cell between passive and active areas, and by the trapping of an aggressive solution inside the crevice. It is mainly a problem for low alloy CRAs, provided oxygen is present in the brine. Common areas to find crevice corrosion include flange joints, threaded joints or small cavities filled with brine.

Galvanic corrosion occurs when two dissimilar metals are in contact, and at the same time having a liquid connection between the two metals. In geothermal systems, oxygen reduction is the only likely cathode reaction for driving this process. Thus, galvanic corrosion is only considered, if oxygen ingress happens.

The principle of galvanic corrosion is comparable with a battery cell. If the metals are more than 0.1-0.2 V apart in the galvanic series, there is a considerable risk of corrosion of the less noble metal on behalf of the more noble metal. Stainless steel is ~0.6 V more noble than carbon steel in geothermal brine, thereby presenting a risk of galvanic corrosion. If the surface area of the noble metal is much larger than that of the less noble metal, the unfavourable area ratio will lead to extremely rapid corrosion. Due to the high electrical conductivity of the brine, the galvanic element includes surfaces over long distances, making this mechanism particular dangerous in geothermal plants.

For the same reasons, care must be taken when defining the welding procedure for steel tubing in geother-mal plants to avoid galvanic differences between the weld metal and the parent pipe metal. Usually, weld metal is added small amounts of nickel and chromium to optimise the mechanical properties. The addition of such noble elements would typically imply higher corrosion resistance of the weld than the parent metal, but in some situations the effect is opposite leading to a phenomenon known as Preferential Weld Corrosion (PWC). It is always advised to make a prequalification corrosion testing of the welding procedure to avoid this problem before building the plant.

A special form of galvanic corrosion, involving noble metal deposition, can happen in geothermal plants. In certain reservoir types, the brine contains dissolved metal ions, such as lead (Pb2+) in the Bunter reservoirs. And in Germany, dissolved copper ions (Cu2+) has caused galvanic corrosion in one plant.

The tendency for lead deposition increases with increasing temperature and flow rate. Consequently, the production well and tubing are more vulnerable to this form of corrosion than the other sections.

Carbon dioxide (CO2) is a weak acid when dissolved in water and thereby potentially corrosive to steel. The corrosion rate mainly depends on the partial pressure of CO2, which can be high in pressurized systems like geothermal wells. By this CO2 becomes almost an inexhaustible source for the cathode reaction. There is vast experience from oil and gas production, where CO2 dissolved in the produced water is known to cause considerable corrosion. In the Danish geothermal wells only a small fraction of the gas from the production well is CO2 (0.5-3.6%), whereas methane (CH4) and especially nitrogen (N2) make up the majority.

The mechanism of CO2 corrosion involves formation of a partly protecting iron car-bonate film, leading to localised corrosion of the steel. Usually, the corrosion rate increases with temperature up to a maximum at about 70-80 °C. At higher temperature, the carbonate film becomes more stable leading to slower corrosion. Thus, the conditions in the production well (high temperature, high pressure) represent the greatest risk for CO2 corrosion. Flow rate and buffer capacity of the brine are also decisive for the stabil-ity of the carbonate film and the resulting pH at the surface.

Local high flowrates causing turbulence usually increases the corrosion rate of especially unalloyed steel by constantly removing the formed rust layer from the surface. This will happen if pipe bends are too sharp, and in extreme cases, erosion occurs too on the surface. Likewise, sudden pressure changes due to reduced sections in the pipework can lead to cavitation from the impact of collapsing gas bubbles on the surface. Supersaturation with dissolved gasses accelerate this mechanism further. However, usually the design of the plant is made to avoid such flow related degradation mechanisms by following well-established rules for hydrodynamic engineering.

By providing your well's brine composition, it can be compared to other wells in our database using Principle Component Analysis (PCA). PCA is a dimension reduction method that transforms a dataset with many variables into one with fewer (we use 2), while keeping the amount of variability in the data as high as possible. This video gives a short, informative explanation on the basics of PCA.

By plotting the reduced data, similar wells will show up close to eachother. Once you find which well is most similar to yours, the PERFORM website can be used to find comparable wells, and identify any problems encountered in those wells as well as their corresponding solutions.

Brine composition
Cl
mg/L
Na
mg/L
Ca
mg/L
Mg
mg/L
Sr
mg/L
K
mg/L
Mn
mg/L
Ba
mg/L
Pb
mg/L
SO4
mg/L
EN   i
%

Gas composition
O2
vol%
N2
vol%
CO2
vol%
CH4
vol%

PCA result:

Well with most similar brine composition to your well:

The severity of corrosion depends on a number of factors, including: the primary driver of the corrosion process (either dissolved CO2, oxygen ingress, the presence of lead ions), the amount of the driver present in the brine, the average flowrate of the brine in the well tubing, the well dimensions, and operating conditions. By filling in the fields in the calculator below, a rough estimate can be made on the amount of corrosion within the well on a yearly basis.

Results are based on worst-case scenario calculation to give an impression of the impact corrosion may cause on particle release. It is assumed that iron forms magnetite (Fe3O4) which is the normal corrosion product in water with almost no oxygen.

CO2 corrosion calculations are based on the Norsok-506 standard. The calculation for oxygen and lead ion driven corrosion are based on simplified stoichiometry.

Please note that these calculations are only here to give a general indication of the corrosion potential. All calculations assume single-phase flow, and do not take into account the interplay between multiple corrosion types, combined corrosion and scaling, or the operating strategy of the well. Decision should not be based on these results, consultation with an expert is required when you think corrosion might be affecting your wells. See the terms of use (top right of page) for more details.

Corrosion driver
Temperature
°C
Pressure
bar
Bicarbonate concentration
mg/L
CO2 percentage in gas
mol%
Ionic strength
Average flowrate
m3/hr
Tubing length
m
Tubing diameter
m
mm/year

There number of possible strategies an operator can take to mitigate the effects of corrosion. Which are best suited and will have the largest impact depend of course on the type(s) of corrosion present in the well. The list below gives the possible mitigation strategies based on the inputs provided in the "corrosion types" tab.

Click on any of the options to expand it for more details.

It is always of outmost importance to keep the system deaerated, including start-up, operation, shutdown and standstill periods. Air entering the waterfilled system will lead to corrosion of carbon steel and possibly also low-alloy stainless steel.

As a basis, the brine from the reservoir is completely free from oxygen. Thus, possible ingress of air is related to operations in the plant (draining, repair, filter replacement etc.) or faulty and inadequate maintenance of equipment (leaking seals in pumps etc.). Efforts should constantly be applied to minimize the air entering the system from such sources.

During normal operation, the risk of oxygen ingress is usually very small, especially if the system is pressurized. The injection pump represents a potential risk area for air-intake at the seal for the pump shaft due the suction forces. Usually, a special device prevents this from happening by applying a pressure of liquid and nitrogen on the outside of the seal. However, if not operated correctly, oxygen ingress could occur at this location while the pump is running. If the surface plant operates at slight underpressure, the risk of oxygen ingress is even higher and strict procedures should be established, e.g. continuous dissolved oxygen monitoring.

During shutdown for summer periods or repair, special precautions are also required to minimize air, entering the system. In most cases the system remains water-filled without circulation. Some equipment may by disconnected and opened, e.g. filters and heat exchangers. When refilling and reconnecting such equipment, air will inevitably enter the system. Blanketing and pressurizing with inert nitrogen gas are commonly used to displace air as a good practice.

Dosage of oxygen scavengers may be considered to limit the effect of oxygen during shut-down and stand-still depending on the amount of oxygen entering the system. Sodium sulfite, ammonium bisulfite or sodium bisulfite are frequently used in systems such as water injection systems, comparable with the geothermal circuit. Sometimes a catalyst is added in ppb concentration (e.g. cobalt) to speed up the reaction. However, before applying oxygen scavengers the potential risks and side-effects should be evaluated closely. As an example, sulfate and perhaps H2S formed by the reaction with sulfite could promote growth of sulfate reducing bacteria (SRB). Thus, it may be beneficial to add a biocide simultaneously together with the oxygen scavenger.

The only way to prevent corrosion due to metal ions is adding corrosion inhibitors. Corrosion inhibitors form an organic film on the metal surface, thereby obstructing the metal deposition and galvanic reactions from occurring. The efficiency depends on dosage concentration, flow, temperature and surface finish of the steel. It is advisable to conduct corrosion testing in a laboratory before deciding on the inhibitor type and dosage. Continuous corrosion monitoring in the operating plant is also recommended as discussed later.

In the surface plant, where the pressure is relieved, CO2 may come out as a separate gas phase. Removing the CO2 gas from the brine in a de-gasser will be beneficial to avoid corrosion of downstream equipment. However, the resulting increase in pH could on the other hand affect the stability of the brine, leading to scale formation (e.g. calcite). Consequently, a geochemist should be consulted before installing a de-gasser.

Below, a short overview of the result of the corossion well check is given

Corrosion types
Brine comparison
Corrosion rates
  • CO2: N/A mm/year
  • Oxygen: N/A mm/year
  • Lead: N/A mm/year
Corrosion mitigation

Scaling well check

The changes in conditions that the geothermal fluid will be subjected to, from subsurface to the surface and injected back to the aquifer, will lead to changes in the brine properties and the potential risk of mineral deposition and scaling. Some of these condition changes include: the temperature decrease during the production and heat extraction of the geothermal brine, the pressure decrease of the geothermal brine in the production casing and surface facilities, the temperature and pressure increase in the injection wells of the geothermal brine with a new equilibrium (filtered or partially precipitated brine), and the depressurization of the brine in the separator or degasser.

Scaling precipitation could impact the production and injection by increasing the hydraulic resistance, i.e. the resistance to flow. Additionally, it can reduce the heat transfer rate in the heat exchangers and reduce the overall COP (Coefficient of performance) of the system.

In this wellcheck, an overview of different types of scaling will be given, along with methods for monitoring and mitigating these issues. Unlike corrosion, it is impossible to predict or quantify the type or amount of scaling occurring within a geothermal well without an extensive measuring and modelling campaign. For this reason, the scaling wellcheck contains fewer parts in which you are asked to provide input (only for the brine comparison).

While the number of potential minerals/compounds that could form scales inside a geothermal well is large, they can generally be divided into three types, each of which occur under different conditions and are driven by different processes. These three types are: carbonate scales, sulphate scales, and heavy metal scales, and are listed below. Click on any of the names to see further details.

Carbonate scales occurs in low-enthalpy geothermal systems. Carbonate scaling is primarily related to (partial) outgassing of the produced geothermal water during geothermal production. The naturally dissolved gas in geothermal water comes out of solution if the pressure is decreased sufficiently at the surface. The pressure at which natural gas is released is called the bubble point and depends on the reservoirs gas content, pressure, temperature and salinity and hence is specific for each doublet.

The gas composition in low-enthalpy geothermal doublets are mainly containing CO2, CH4 and in few cases N2 (e.g. Dutch doublets are dominantly methane, but CO2 typically makes up 5-10% of the total gas pressure). The process of carbonate scaling is governed by CO2 release from the water causing a pH increase, which reduces the solubility of carbonates. The reduced solubility causes carbonate precipitation, forming scales in the surface installation. Depending on the water composition, any carbonate can precipitate but for the calcium rich waters of the Delft sandstones, mainly calcite and minor siderite is observed.

Although the main pH change of the water will already occur in the gas-liquid separator, calcite scaling has often been observed further downstream of the system such as in the filters. This is most probably related to the availability of particles/sites for nucleation of carbonate crystals.

Carbonate scaling is highly unlikely in the system after the temperature drop at the heat exchanger since carbonate solubility, unlike most minerals, increases with decreasing temperatures. Note that, besides the pressure dependence, calcite scaling can also occur due to temperature increase such as in high temperature storage. The pressure or pH dependence and the influence of temperature on carbonate scaling can be predicted with geochemical modelling software.

Barite or other sulphate scales in the production wells can significantly reduce the flow diameter of the tube in oil and gas wells. The solubility of barite goes down with decreasing temperature or pressure and goes up with increasing pH and/or salinity. Since the pH dependency is negligible between 2 and 6.5 (only at pH of 9 to 10 the solubility decreases), the pH effect is not relevant for most geothermal systems.

The main trigger for barite precipitation in geothermal systems will be the temperature decrease. As a result, barite scales can occur in the heat exchanger, injection well and near well area. Barite has been observed in filters, but major issues with barite have not yet been encountered in geothermal operation. Numerical simulations do indicate that barite slowly forms in the reservoir due to its slow reaction rate and delayed precipitation. However, it has also been argued that barite only precipitates and cause injectivity issue when the saturation index approaches values over 1 or even over 3.

Experience with geothermal systems indicates that the saturation threshold for nucleation is rarely exceeded to a degree that allows barite scale formation. At Groß Schönebeck, substantial amounts of barite scales were observed in the production well. The formation water at this site is hot and very Ca rich and it is proposed that the barite formation relates to the significant decrease of the stability of the CaSO4 ion pair with decreasing temperature. Predictions of sulphate scaling can be done with geochemical modelling software, but the models do require assumptions on the saturation threshold for precipitation.

Heavy metal scaling is a well-known problem in geothermal systems. Heavy metal (e.g. lead, copper or mercury) can form scales due to salt oversaturation or electrochemical reaction with the steel casing, i.e. galvanic corrosion. Examples of heavy metal scaling are lead carbonate, elemental lead, or iron scales such as pyrite or magnetite.

Heavy metal scales are common for geothermal systems targeting the Rotliegend Formation and mainly the lead and copper originating can cause issues during geothermal production. The high heavy metal content of Rotliegend waters originates from the overlying Kupferschiefer formation or Carboniferous coals. For example, Dutch geothermal systems in the Rotliegend Formation are prone to lead scaling due to the relatively high lead concentration of the formation water.

Corrosion of steel can cause elemental lead deposition by the reduction of lead ions using electrons released by the oxidation of iron from the steel components of the wells or surface installations.

Lead scales have been identified as cerussite instead of elemental lead with no sign of corrosion enhanced lead scaling. Lead carbonate, called cerussite (PbCO3), is a carbonate mineral which, in contrast to calcite, dolomite and siderite, has a lower solubility at lower temperatures. The heat exchanger, injection well and near-well area are therefore more prone to this type of scale than other carbonate scales.

Pyrite and magnetite scaling can be caused by dissolved H2S corrosion of the carbon steel casing, as has been observed in geothermal systems in the Molasse Basin. Fe(III) oxides or hydroxides are generally induced by increased dissolved oxygen concentrations. Heavy metal scaling may occur by different processes depending on the targeted reservoir and the doublet material use but corrosion related scaling appears dominant.

By providing your well's brine composition, it can be compared to other wells in our database using Principle Component Analysis (PCA). PCA is a dimension reduction method that transforms a dataset with many variables into one with fewer (we use 2), while keeping the amount of variability in the data as high as possible. This video gives a short, informative explanation on the basics of PCA.

By plotting the reduced data, similar wells will show up close to eachother. Once you find which well is most similar to yours, the PERFORM website can be used to find comparable wells, and identify any problems encountered in those wells as well as their corresponding solutions.

Brine composition:

Cl
mg/L
Na
mg/L
Ca
mg/L
Mg
mg/L
Sr
mg/L
K
mg/L
Mn
mg/L
Ba
mg/L
Pb
mg/L
SO4
mg/L
EN   i
%

Gas composition:

O2
vol%
N2
vol%
CO2
vol%
CH4
vol%

PCA result:

Well with most similar brine composition to your well:

(Direct) monitoring of scaling is not commonly done, below are some common practices to monitor or analyse the precipitated minerals.

  • Flow obstruction by changes in flow rate or pressure may indicate precipitation
  • Material captured in the filters can be analysed to check for precipitates
  • Water chemistry may be monitored, but changes may not be within the accuracy. pH could be measured to monitor calcite scaling potential

There are a number of ways in which an operator could mitigate the severity of scaling inside their geothermal well. These method depend on the type of scaling taking place. Click on the scaling types below for further details on the appropriate methods.

  • Avoid or limit CO2 outgassing by maintaining a sufficiently high operation pressure in the surface installation. A pressure is required that keeps enough CO2 in solution to prevent carbonate precipitation. In general, this pressure may be lower than the bubble point and partial outgassing should not be a problem.
  • Use inhibitors to keep Calcium in solution
  • Use cation filters to remove Ca2+. Such filters could e.g. be based on seeded crystallization (FACT filter)
  • Add acid or CO2 to the brine to prevent decrease the pH and increase carbonate solubility
  • Use scaling inhibitors
  • Use cation filters with adsorption materials for e.g. barium removal (e.g. chitosan or zeolite) prior to re-injecting cooled water
  • Use scaling inhibitors
  • Use corrosion resistant materials
  • Use cation filters with adsorption materials for heavy metal removal prior to re-injecting cooled water

Below, a short overview of the result of the corossion well check is given

Scaling types
  • Carbonate scaling
  • Sulphate scaling
  • Heavy metal scaling
Brine comparison
Monitoring methods
  • Flow changes
  • Filter precipitate analysis
  • Water chemistry changes
Scaling mitigation
  • Carbonate scaling: avoid CO2 outgassing; use inhibitors; use cation filters; add acid or CO2
  • Sulphate scaling: use inhibitors; use cation filters
  • Heavy metal scaling: use inhibitors; use corrosion resistant materials; use cation filters