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The Effect of CO2 Injection on Corrosion and Integrity of Facilities

The complete paper is based upon a company’s experience with regard to carbon dioxide (CO2) enhanced oil recovery (EOR) studies on asset integrity, material selection, and corrosion mitigation. The paper discusses the main factors affecting CO2 corrosion, provides an assessment of what to look for in major equipment, and details recommended material of construction and corrosion mitigation/control methods.

CO2 Corrosion

Along with the benefits of injection of CO2 comes the risk of internal corrosion. Dry CO2 gas is not itself corrosive, but is so when dissolved in an aqueous phase (water is required for corrosion to occur). CO2 is extremely soluble in water and brine and has even greater solubility in hydrocarbons. CO2 dissolves into the crude oil and follows the production and transportation process, and it can dissolve in water and react with iron in carbon steel pipes. Under ideal conditions, iron carbonate (FeCO3) can create a protective layer and prevent further conversion of iron. This protective layer can prevent the cathodic and anodic reactions from taking place.

Sweet and Sour Corrosion Mechanisms. Corrosion primarily caused by dissolved CO2 is commonly called “sweet” corrosion, whereas corrosion caused by the combined presence of dissolved CO2 and hydrogen sulfide (H2S) is referred to as “sour” corrosion. The generally accepted view of the effect of CO2/H2S ratio on the corrosion mechanism is as follows:

  • For CO2/H2S ratios of less than 20, the corrosion is fully governed by H2S. For carbon steels, the primary corrosion product is a nonstoichiometric iron sulfide with varying protective properties depending on its crystallographic structure.
  • For high CO2/H2S ratios, the corrosion rate is fully governed by CO2. The primary corrosion product is FeCO3. The limit ratio is generally taken as 500 but depends on environmental variables.
  • For intermediate ratios, the corrosion regime is complex and difficult to anticipate.

Factors Affecting CO2 Corrosion

Water Wettability. For CO2 corrosion to occur there must be water present and it must wet the steel structure. Wettability is dependent on the fluid and its impurities. When a pipe wall is more water-wet, there is a larger area of contact with the brine and the wall itself. The greater the water wettability, the more likely corrosion is to occur.

In oil/water systems, emulsions can form. If a water-in-oil emulsion is formed, then water may be held in emulsion and water wetting of steel surfaces may be prevented or greatly reduced, leading to a reduction in the corrosion rate. The transition from a water-in-oil emulsion to oil-in-water emulsion occurs at approximately 30 to 40% water in oil; a clear jump in corrosion rate can be demonstrated at that point. This has led to a truism that corrosion is greatly reduced for water cuts of less than 30%.

CO2 Partial Pressure. An increase in the partial pressure of CO2 leads to an increase in the corrosion rate. CO2 corrosion results from reaction of steel surface with carbonic acid. An increase in the partial pressure of CO2 would mean that more carbonic acid could be formed with a greater concentration of cathodic ions to carry out the reduction reaction; thus, the corrosion rate would rise. However, in favorable conditions in which protective scales can form, the corrosion rate is reduced. Increases in pressure increases the precipitation and formation of FeCO3 scales.

Temperature. It is expected that the rate of a chemical reaction increases with temperature. Because more energy is available at higher temperatures, more iron can be oxidized because the activation energy barrier is easier to overcome. For CO2 corrosion where water is a dependent factor there is an exception. At higher temperatures, where water is above the dew point, it does not condense. Without the presence of the condensed water, there is a decrease in the rate of corrosion. Also, with the formation of the protective FeCO3 scale, higher temperatures decrease the solubility of this precipitate, this increasing the likeliness of scale formation.

pH. pH has a strong influence on the corrosion rate because of its effect on the cathodic reaction as well as its indirect effect on the forming of protective scales. The solubility of released corrosion products is reduced by just five times when the pH is increased from 4 to 5. When the pH is increased from 5 to 6, the solubility of corrosion products is increased one hundred-fold.  A high pH reduces the solubility of the ions in water, which leads to a high precipitation rate, thus reducing corrosivity.

Flow Regime and Velocity. The flowing velocity of the fluid affects corrosion in two ways: destruction of protective films and reduction of ion concentrations near the pipe wall. Flow regime of the fluid is very important because it strongly affects the formation of protective films.

When the flow is laminar, films can form without being stripped off. However, when the flow regime becomes transient or turbulent, the protective film is removed and any further formation of a protective layer is prevented. It should be noted that at high flow rates, the film formed in the pits is not as effective at corrosion prevention because the film is more porous and loose.

Effect of H2S. Apart from the cracking and corrosion problems associated with sour service, H2S can have a beneficial effect on wet hydrocarbon CO2 corrosion because sulphide scales can provide protection for the underlying steel. The effect is not quantified, but it does mean that facilities exposed to gas containing low levels of H2S may often corrode at a lower rate than completely sweet systems.

Corrosion Assessment and Mitigation

CO2 Injection System. It is imperative to ensure that the amount of H2O present in the CO2 composition does not form free water. Water analyzers can be helpful at the source of the CO2 Also, regular pigging and proper drying of the line after a hydrotest ensures that there is no water settlement in the pipeline.

Also, the pipelines transporting the CO2 for injection will need to be studied for longitudinal ductile fractures, which can occur in high-pressure pipelines. A plan to make the line fracture-resistant is required. Fig. 1 details the phase behavior of CO2 in a pressure-enthalpy diagram.

Fig. 1—Phase behavior of CO2 from a pressure-enthalpy diagram.

 

Increasing wall thickness helps by reducing stress at the tip of the fracture, and increasing toughness helps by enabling the steel to absorb more energy before it tears. Increasing wall thickness—in this case, to prevent longitudinal ductile fractures in CO2 injection pipelines—can be economically viable because doing so allows the operating pressure to be increased, reducing the number of pump stations and the pipe diameter.

Other methods for controlling ductile fractures include use of crack arrestors and controlling the contaminants through the use of filters in the CO2 carried by the pipeline so that the pressure of the decompressing CO2 at the crack tip is insufficient to cause a fracture to propagate.

Downhole Equipment. As part of one of the CO2 pilots conducted by the company, the oil producer was made of carbon steel with corrosion inhibition above the packer. The downhole completion material of CO2 injector was Super 13 Cr. Initial corrosion modeling predicted high corrosion rates in the producer tubing because of the carbonic acid from the CO2. Corrosion logs carried out during the pilot period indicated active corrosion at the tubing section below the packer.

Following the completion of the pilot, the producer was retrieved. An investigation concluded that the corrosion was confined to the uninhibited tubing section in the reservoir zone. On the basis of these findings, it was recommended to replace the tubing section below the packer with a corrosion-resistant alloy (CRA) and continue with corrosion-inhibition injection for the carbon steel section above the packer of the oil producer.

New Oil Producers. For new oil-producer pipelines, it is necessary to design for the practical worst-case scenario. This includes scenarios of differing possibilities including consideration of CO2 and H2S levels, water cut, temperature and pressure, and flow velocity.

Depending on the CO2/H2S ratio and the water cut, corrosion may be governed by sweet and/or sour corrosion. Also, H2S can have a mitigating effect on the CO2 corrosion at certain ratios with the formation of a semiprotective sulfide film.

For new projects, flowlines and pipelines hold a major part of the total cost; consequently, the decision of whether to iuse carbon steel or CRA is of major importance. Corrosion-modeling software is used to predict anticipated corrosion rates for material selection. It is best to use a software tool that offers more flexibility with regard to the data to be entered and has been proved in similar service, as this will provide more reliable results.

Existing Equipment. As CO2 is injected into reservoirs, it will cause CO2 entry into the production streams of other nearby reservoirs. Existing facilities were not designed to anticipate these conditions and need to be considered on a case-by-case basis. Gathering facilities will see an increase of CO2 ratios in commingled fluids from oil producers. For existing equipment, it is necessary to study the purpose for which they were initially designed. It is also critical to evaluate the current condition of existing equipment (i.e., remaining wall thickness).

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 182955, “The Impact of CO2 Injection for EOR and Its Breakthrough on Corrosion and Integrity of New and Existing Facilities,” by Abdulla Luqman and Ali Moosavi, ADCO, prepared for the 2016 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 7–10 November. The paper has not been peer reviewed.

 

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