Influence of corrosion on casing strength


Corrosion can pose a major threat to the installations whether above or below ground. With particular respect to casing, corrosion can impair the ability of the casing to perform its functions in two ways. Firstly, metal loss will reduce the wall thickness of the casing and hence its capacity to withstand the design loads. Secondly, corrosion can weaken the casing material so that it can no longer withstand the design loads.

1 Introduction

 The management of this threat is dependent on the following factors:

  • the awareness of all staff involved of the importance of corrosion as a factor in design;
  • the awareness of all staff involved of the importance of corrosion control during operations;
  • the feedback of corrosion experience both to guide immediate operations and to influence design standards for the future.

In many Operating Companies specialist corrosion engineers are available to assist in all phases of the corrosion management process. It is therefore the intention of this section to provide basic guidance for the casing designer in recognising corrosion threats and in identifying possible solutions that can be applied at the design stage.

1.1 Site of downhole casing corrosion

In casing design there are three basic causes for corrosion that should be considered:

1.internal casing corrosion due to reservoir fluids within the well;

2.internal and external casing corrosion due to drilling, workover, and completion fluids;

3.external corrosion due to formation fluids, reservoir fluids, and surface water.

a. Internal casing corrosion due to reservoir fluids in the well

Reservoir fluids can be corrosive; this is one of the reasons why these reservoir fluids are normally contained within the tubing. Generally, the only internal part of the casing in contact with the reservoir fluids is the part below the production packer. Nevertheless, there are circumstances where other internal parts of the production casing may be exposed to reservoir fluids e.g. beam pump operations, a tubing/packer leak, or during workover and remedial operations. The intermediate casing may be similarly exposed e.g. during circulating out an influx.

b. Internal and external casing corrosion due to drilling, workover completion and stimulation fluids

Fluids used during the drilling and completion phases can be corrosive, or can become corrosive when exposed to high temperature for extended periods. Examples of corrosive fluids are muds and brines with a low pH, while packer fluids and mud left in annuli can become corrosive due to a drop in pH with time and/or increased temperature. Also, stimulation fluids should be assessed for their corrosive nature.

c. External casing corrosion due to fluids from external sources

Uncemented casing opposite formations containing corrosive fluids can be subject to attack. Corrosive fluids can be found in water rich formations and aquifers as well as in the reservoir itself. At surface, all wells will be exposed to rain water and air moisture. For offshore wells, the combination of salt water and oxygen gives a particular problem in the splash zone.

1.2 Casing materials

Steels for use in casing are supplied by manufacturers in a wide variety of grades. The materials can be differentiated in terms of chemical constituents and also in terms of method of manufacture (heat treatment). API Specification 5CT Section sets out composition and heat treatment requirements for the API grades. However manufacturers also produce their own proprietary (i.e. non-API) grades with claimed performance advantages over the equivalent API tubulars.

The great majority of casing materials are carbon steels. Casing steels differ from current pipeline steels in that they contain rather larger quantities of elements such as carbon which allow higher strength grades to be produced, often by heat treatment.

The welding of casing is a very specialised process involving both pre- and post-weld heat treatment. Without this approach welds will be very hard and subject to cold cracking due to hydrogen and brittle fracture. Welding of casing should not be attempted in the field and the practice of welding casing head housings should be strongly discouraged.

Corrosion resistant alloy (CRA) casing materials often achieve the required strength levels by cold working (e.g. 145,000 psi (999,775 kPa) yield strength for Incoloy 825). Their corrosion properties usually reflect those of the corresponding lower strength materials.

2 Common types of corrosion

2.1 Introduction

The following provides a brief outline of the forms of corrosion which can occur in, but are not limited to, casing.

2.2 General corrosion

This is a reaction between a metal and any corrosive well or formation fluid which leads to general rather than localised metal loss. The fluids may be muds or brines, produced fluids or formation fluid which are allowed into contact with the casing steel.

2.3 Galvanic corrosion

This form of corrosion results from the differing electrochemical potentials of different metals or different areas of the same metal in an electrolyte (an electrically conductive fluid) which also contains a corrosive agent such as oxygen or carbon dioxide. The potential differences create a cathode-anode pair and metal loss from the anode results.

2.4 Pitting

As casing corrodes, the resulting corrosion product may adhere to its surface thus limiting further attack. Subsequent local layer breakdown due to electrochemical effects or physical removal can expose bare metal to the electrolyte. This exposed area becomes anodic with respect to the protected surrounding metal. Galvanic corrosion at these areas can cause pitting damage.

2.5 Differential-aeration corrosion

When different areas of a carbon steel casing are exposed to electrolytes with different oxygen concentrations, a galvanic cathode-anode pair is generated and metal loss from the anode results.

2.6 Carbon-dioxide corrosion

When CO2 dissolves in water it leads to the attack of carbon steel through a series of complex reactions. Temperature of exposure and the partial pressure of CO2 play important roles in determining the degree of corrosivity.

2.7 Hydrogen-sulphide corrosion

Hydrogen sulphide (H2S) can produce many forms of corrosion - general attack, pitting, hydrogen embrittlement (HE), hydrogen-induced cracking (HIC) and sulphide-stress-corrosion cracking (SSCC).

The first two of these are considered above. The last three are all related to the uptake of hydrogen into the metal lattice.

a. Hydrogen embrittlement (HE)

Hydrogen atoms generated by galvanic action at a metal surface can absorb into the structure of the metal where they increase the strain in the lattice. This reduces the ductility and the metal can fail in a brittle manner, failure often originating at stress concentrations. For high strength steels, highly alloyed materials are often more resistant to SSCC (see below) than similar strength carbon-manganese steels but can be susceptible to hydrogen embrittlement when, for example, hydrogen charging results from galvanic corrosion.

b. Hydrogen-induced cracking (HIC)

Hydrogen atoms absorbed into a metal lattice can collect in areas of inclusions forming gas molecules. Over time the gas pressure can rise until it is great enough to cause the grains to part and cracks to initiate (usually initially parallel to the metal wall). Crack propagation along and particularly through the wall (step wise cracking) can lead to sudden failure.

c. Sulphide-stress-corrosion cracking (SSCC)

Stress corrosion cracking requires a high level of applied or residual stress in a corrosive environment. High strength carbon-manganese steels are particularly vulnerable to this form of attack in H2S containing media. Hydrogen uptake embrittles the material in the area of stress concentration at crack tips which then can propagate in the corrosive environment. SSCC becomes less likely to occur at temperatures permanently above about 150°F (65°C).

2.8 Chloride-stress-corrosion cracking (SCC)

This form of attack, most commonly referred to as stress corrosion cracking, involves an anodic corrosion process in which corrosion occurs at stress induced failures in a passive metal surface film. The process is stimulated by the presence of chloride ions but its propagation requires the presence of a corrosive agent such as oxygen. The best known example of this type of damage is chloride stress corrosion cracking of austenitic stainless steels such AISI 316. Unlike SSCC, the risk of SCC increases with increasing temperature above a threshold of about 140°F (60°C).

2.9 Bacterial corrosion

Sulphate reducing bacteria (SRB) can produce hydrogen sulphide when under anaerobic (oxygen free), sulphate containing conditions. This can happen in the ranges of pH 5.5-9 and, in general, only at temperatures less than about 176°F (80°C).

2.10 Erosion/corrosion

Fast moving fluids and solids can strip a metal of its protective oxide, sulphide or carbonate layer. The exposed surface then reacts to reform this protective layer and this cycle is repeated producing a high rate of attack.

2.11 Intergranular corrosion

During heat treatment, either during or after manufacture, metallurgical changes can result in a lower corrosion resistance at material grain boundaries than in the matrix. Exposure to a corrosive environment can then cause intergranular attack through local galvanic corrosion reactions.

3 Prevention and control of casing corrosion

The following sections address the most common corrosion and materials problems which are met in casing and conductors. Possible solutions to these problems, often involving implementation at the design stage, are put forward.

Forms of corrosion which can lead to sudden and rapid failure (SSCC, SCC, HE) should always be designed for. In dealing with gradual metal loss corrosion, engineering judgement must be used to determine whether the extent, and consequences, of a loss of wall thickness justify a change in casing thickness or material.

3.1 Internal corrosion due to reservoir fluids

a. Production casing below production packer

Unlike the rest of the production casing, the part below the production packer is continuously exposed to the (flowing) reservoir fluids and, unlike the production tubing, no internal corrosion inhibitor can be applied nor can the casing be readily retrieved for maintenance.

If the fluids locally lead to water wetting of the casing material, corrosion of carbon steel will take place. CO2, H2S or O2 (in the case of the injection of untreated water) can all lead to corrosion or corrosion-erosion. The levels of water required before water wetting of steel occurs vary. Water cuts above 30% and in deviated wells flow velocities below 3.3 ft/sec (1 m/sec) for any water level, are liable to lead to corrosion. For certain oil compositions evidence suggests that, even at levels of about 1% water, corrosion can occur for velocities possibly as high as 6.5 ft/sec (2 m/sec).

To prevent corrosion in this part of a casing the same material selection criteria should be applied as would be used for long life production tubing under the same conditions. No general rules have yet been formulated to guide this choice and expert advice should be sought. Any possible requirement for formation stimulation by acidization and its likely effects on the materials used must also be borne in mind. For example, use of a stimulation fluid such as HCl may result in severe corrosion of CRA tubulars.

b. Production casing above production packer

Normally the exposure time of the production casing (with an inhibited packer fluid ) to corrosive conditions will be too short to result in serious weight loss corrosion on the inside of the casing.

However, the result of extended contamination of a chloride-containing packer fluid with H2S can lead to pitting corrosion which will become more severe with increasing temperature. If applicable, maintaining a pH> 10 can prevent this form of corrosion.

Whilst contamination of an annulus with CO 2 in the packer fluid will lead to attack, rates in an essentially stagnant environment are likely to be relatively low. Assuming such faults are corrected in the short term, damage will remain limited.

Contamination of an annulus with O 2 for long periods is generally improbable and corrosion forms involving this corrosive, such as pitting (of steel or CRAs) or chloride stress corrosion (of CRAs) are unlikely. For beam pumped wells oxygen contamination is a risk and corrosion is possible. It is likely, however, that the use of carbon steel casing will still represent the most economically attractive approach.

In the event that a CRA is used for the production casing, the possibility of chlorides in the packer fluid supporting stress corrosion cracking by, for example H 2S, must be considered (SSCC).

c. Casing materials liable to attack by H2S

All casing strings which may be exposed to sour gas (H2S) should consist of material which is resistant to SSCC at the conditions in which it will be used.

NACE (National Association of Corrosion Engineers) document MR 0175-91 defines a sour gas environment as one where the total pressure exceeds 65 psia (448 kPa) and the H2S partial pressure exceeds 0.05 psia (0.34 kPa).

The immersion of stressed, high strength casing materials in such an environment can lead to the rapid and sudden failure of those materials due to SSCC. The ability of the casing material to resist SSCC increases with temperature.

The risk of SSCC therefore increases with:

  • increasing H2S partial pressure;
  • increasing steel hardness (and hence strength);
  • increasing stress (residual or applied);
  • decreasing pH of the solution;
  • decreasing temperature.

The need to design for sour conditions will primarily depend on the wellbore pressure and the H2S concentration.

The table below shows, for various well pressures, the H2S concentration above which sour service materials are required.

The relationship between SSCC, heat treatment, and steel hardness has been documented by laboratory and field service data. Since hardness testing is non-destructive, it is used by manufacturers as a quality control method, and by users as a field inspection method. Although a maximum hardness of 22 Rockwell C is specified by NACE, use of API grades up to and including L80, which has a maximum hardness of 23 Rockwell C, is accepted based on laboratory evaluation and field experience.

Materials which do not meet this hardness requirement, generally all steels with a minimum yield strength greater than 80,000 psi (551,600 kPa), can be qualified for sour service using laboratory-based testing procedures. NACE document TM 0177-90 describes four such SSCC resistance testing procedures. The first of the procedures - known as the NACE Standard Tensile Test - is most commonly applied, although there is discussion within the oil industry as to which of the four test methods is most suitable and reliable. The NACE Standard Tensile Test requires demonstration that the material is resistant to SSCC at an applied level of tensile stress. It is the purchaser's responsibility to specify the required stress level. Manufacturers typically supply proprietary, i.e. non-API sour-rated materials having minimum yield strengths of 80,000 psi (551,600 kPa) and above, which have been qualified using the tensile test at 80%, 85%, or 90% of the minimum yield strength.

The second test method - known as the NACE Standard Bent Beam Test involves stressing the sample specimen beyond its yield strength. A critical stress (Sc) value is calculated from the test data and is used to relate resistance to SSCC.

Manufacturers should demonstrate the ability of their material to reach the minimum Sc values indicated in the table below:

It is important to note that proprietary sour service materials qualified by the NACE Standard Tensile Test method only cannot necessarily be safely used to their full minimum yield strength under sour conditions.

It is current policy therefore, to require qualification using more severe testing methods. Results of the NACE Standard Tensile Test are not considered an adequate guide to field performance. Whilst alternative tests are being investigated, the Bent Beam Test is currently recommended.

To illustrate the large number of proprietary sour service tubulars available, the table below shows those products supplied with a 95,000 psi (655,025 kPa) minimum yield strength. Prior to the inclusion of any of these products, or any other proprietary sour service materials, in a casing design, satisfactory Bent Beam Test results must be obtained.

Manufacturer Product

British Steel Corp.BSC SR-95

DalmineD 95-SG

Mannesmann MW-95SS


SumitomoSM 95S, modified SM 95S

TamsaTC 95

VallourecC-95 VH-1, C-95 VH-2

KawasakiKO 95S

Lone-StarLSS 95 SGS


It is often argued that the control of mud pH or the use of H2S scavenging muds make the use of such special casing materials unnecessary. However, studies have shown [206] that when the wellbore is displaced to gas, drilling fluids cannot be relied upon to prevent SSCC.

The risk of SSCC decreases with increasing temperature. As a result, high strength, hence high hardness, materials that are not qualified for sour service at low temperatures can be used in parts of the well where the minimum continuous temperature exceeds 150°F (65°C). Still higher strength materials can be used for minimum temperatures exceeding 175°F (80°C).

The application of casing materials in sour service conditions, where SSCC can occur, is summarised in the following:

All temperaturesTemperatures above 150°F (65°C)and below 175°F (80°C)Temperatures above 175°F (80°C)

API Spec 5CT Section grades:- J55- K55API Spec 5CT Section grades:- J55- K55- L80- N80 (quenched and tempered)- C95API Spec 5CTSection grades:- J55- K55- L80- N80- C95- P110

C95 (quenched and tempered) tested and manufactured in accordance with Dr-1-2/3[206]Quenched and tempered proprietary grades with 110,000 psi (758,450 kPa) maximum yield strengthQuenched and tempered proprietary grades with 140,000 psi (965,300 kPa) maximum yield strength

Note that selection of materials in accordance with the above table does not offer protection against hydrogen induced cracking (HIC).

Where a corrosion resistant alloy (CRA) is to be used in a H 2S environment the NACE guidelines are less reliable and expert advice should be sought

3.2 Internal and external corrosion due to drilling, workover and completion fluids

a. Annuli between casing strings

Some muds or brines left in annuli after the completion of a well can degrade with time, especially at elevated temperature [192]. This degradation can lead to a decrease in pH and the associated increase in corrosivity. Casing exposed to such acid muds/brines (pH < 7) will suffer attack until the acid formed has been depleted.

The presence of sulphate reducing bacteria (SRB) in muds or brines containing sulphates with a pH below about 9 can lead to the generation of H2S and a further lowering of pH.

Highly alkaline (pH > 10), thermally stable muds/brines should, where possible, be selected. Such high pH muds/brines also prevent SRB activity and corrosion by residual oxygen. Where such muds cannot be used, treatment of the mud during drilling should take account of possible H2S removal.

Alkaline brine (circulated into a well as soon as possible after completion) assists in corrosion prevention but may be highly damaging to in-flow in certain types of reservoir. Such brines should be selected only in close consultation with the Production Chemistry Department.

b. Tubing/production-casing annulus used for gas lift

Two possible sources of corrosion in a tubing-casing annulus used for gas lift must be considered: the use of water wet injection gas and the presence of a water pocket above the packer but below the injection valve.

The injection of water wet gas can lead to corrosion of both the inside of the casing and the outside of the tubing. Any liquid water which is introduced as a result of condensation in gas lift supply lines or in the annulus itself will tend to drop out in the annulus and will be particularly aggressive. The corrosion mechanisms will depend on the gas composition, with CO2 often playing an important role.

The injection of water-dry gas will not lead to the occurrence of corrosion whatever the gas composition involved if the annulus is also water free.

For gas lifted wells corrosion has been observed in the water pocket above the packer but below the gas injection valve. Corrosion may be accelerated by galvanic effects if the tubing is a CRA whilst the casing in this region remains carbon steel.

The corrosion can be prevented, when dry gas lift gas is used, by the initial displacement of the water pocket to a non-conducting fluid, such as diesel. Where a CRA tubing is present the use of CRA casing up to a point above the gas injection valve could also be considered.

Contamination of lift gas with O2 can lead to very corrosive gas mixtures, especially where water is present.

3.3 External corrosion due to reservoir fluids, formation fluids and surface water

a. Outside of casing strings exposed to reservoir fluids

The same considerations apply as for the inside of production casing below the production packer.

b. Outside of casing strings exposed to formation fluids

Casing may be exposed to water rich formation zones or aquifers. If the water phase is contaminated with CO2, H2S, O2 or other corrosive agents, corrosion may result.

Particular attention must be paid to zones where H2S may occur, at a level above a partial pressure of 0.05 psi (0.34 kPa) (the NACE MR.01.75 threshold and at temperatures below 150°F (65°C). Such conditions can produce sulphide stress corrosion cracking (SSCC) in high strength casing steels.

Differences in levels of such dissolved gases between zones, or other differences in formation water compositions can also lead to galvanic cells which further accelerate corrosion.

The primary barrier to corrosion is adequate cementation with a suitable cement which provides an alkaline environment next to the steel surface. At a pH greater than or equal to 10 none of these corrosives (H2S, CO2, O2) will cause attack. However, as even the best cement is considered permeable the pH will stabilise at lower values, because of the interaction with the formation. Poor cement jobs (or not cementing at all) can leave the external surface of a casing exposed to corrosive attack.

If circulation problems occur preventing an effective cement job, and serious corrosion of the casing is expected as a result, remedial action should be taken.

Whilst not routine practice some companies apply cathodic protection in special cases. If there is clear evidence of the corrosivity of some formations, and there are no intervening strata of such low electrical conductivity that the penetration of sufficient current to achieve cathodic protection is not feasible, this approach can provide a means of preventing corrosive attack.

c. Conductor casing

Current designs for offshore platform wells and land wells involve having an open annulus between the marine conductor or stove pipe and the conductor casing. This annulus inevitably becomes filled with (salt) water which promotes oxygen corrosion on the outside of the conductor casing and the inside of the marine conductor or stove pipe, particularly close to the water level. Where a marine conductor is perforated near the mudline this problem is made worse by the inflow and outflow of oxygenated sea water with wave and tidal movements. The design manual for marine conductors is being updated to address this problem.

Possible solutions will include cementing the annular space to the highest possible level or sealing the unfilled annulus against oxygen ingress. The former will ensure that any corrosion (of the inside of the marine conductor or stove pipe and outside of the exposed conductor casing) which occurs will be limited to the zone above the top of the cement and should be relatively accessible for inspection (usually by external ultrasonic techniques). The latter solution would also involve resealing any perforations of the marine conductor required during drilling.

At present, little is known about the long term stability of alternative "safe" liquids such as inhibited water or gels (especially when oxygen is not also excluded) and they cannot be recommended.

d. Marine conductors

Internal corrosion of marine conductors is addressedabove. This section will deal with external corrosion of marine conductors.

A marine conductor can be divided into three zones with different environments: a zone exposed to the atmosphere, the splash zone and the submerged zone. All zones are subject to oxygen attack which can take the form of general corrosion or pitting.

In the zone exposed to the atmosphere above the conductor guides, corrosion can be prevented/controlled by painting.

In the splashzone, where corrosion is most severe because of constant rewetting of the steel, maintenance coating of the conductor is difficult. In addition, coatings cannot withstand the sliding forces as the conductor passes through the guides and coatings applied initially are scraped off. Often no coating is applied for this zone but use is made of a substantial corrosion allowance. Information concerning splash zone corrosion rates can often be obtained from jacket inspection data available locally and these should be used to set the corrosion allowance. Guide damage and difficulty in predicting the exact depth to which conductors will penetrate preclude the use of the splashzone protection methods used for flowline risers.

In the submerged zone corrosion is prevented by cathodic protection and allowance should be made for the conductors in the cathodic protection design for the platform.

3.4 All-round corrosion

Certain forms of corrosion can arise in any part of a casing string.

Galvanic corrosion

If different metals are used within the same string (either for the casing tubulars or the couplings) or adjacent casing strings, and are in electrical contact with each other via an annulus fluid contaminated with a corrosive agent such as CO2, H2S or O2, galvanic corrosion might occur [201] section 2.5. Under similar circumstances galvanic cells can develop between differently heat-treated zones of the same material. For example "ring worm" attack can occur at the metallurgical different zone produced at the transition between the end and body of a tubular during upsetting. Full length heat treatment after upsetting avoids this problem. In general avoidance of contamination with CO2, H2S or O2 should be achieved to prevent this form of attack.

3.5 Special forms of corrosion

Liquid-metal embrittlement

Several unexplained high strength casing failures have occurred in deep wells at temperatures above 330°F (165°C). In one case, the tubular connections had been tin plated, and in others, thread lubricant containing lead, tin and zinc had been used. Laboratory testing at the temperatures to which the connections had been exposed in the well resulted in rapid cracking of the collars. Metallurgical examination showed that the cracking was the result of liquid metal embrittlement. This is a form of intergranular attack. When heated to sufficiently high temperatures, metals such as tin and zinc (which are in connection thread compounds) will melt and flow along the grain boundaries of adjacent metals which have not melted. The grain boundary zone is then weakened and the metal becomes brittle. These results indicate that lubricants should only be applied at temperatures below the melting point of any metallic components they contain.

3.6 New developments

Two trends in drilling with potentially major impacts on the casing materials used are:

  • deeper, high pressure and high temperature wells are being drilled, the well fluids sometimes being very corrosive;
  • wells are being drilled in more and more remote areas and hostile environments (e.g. deepwater and Arctic wells).

The first trend requires higher strength steel grades for casing. This represents a problem for sour service. At present API is involved with a project to qualify C90 and T95 API grades for sour service. The acceptability of these grades for use will be dependent on the qualification tests and criteria for acceptance used. Until now, qualification for inclusion in NACE MR0175 has been based on the NACE TM0177 tensile test at a stress level which is a proportion (e.g. 85%) of the minimum specified yield strength. This is not considered acceptable since in practice stress levels higher than this level may occur, particularly at couplings.

The current view is that the qualification of this and higher grades (100,000 psi (689,500 kPa) and 110,000 psi (758,450 kPa) minimum yield strength) for sour service should be based on the Standard Bent Beam Test. It is realised that for some applications involving low amounts of H2S this may be rather conservative.

Since the costs of repair and workover operations tend to be very high in remote areas and in hostile environments, wells in such areas should be designed with the aim of low maintenance costs in mind. If conditions are such that casing corrosion can be expected, it might be economically attractive to spend more money at the design/initial construction stage to achieve corrosion prevention than might be the case for wells in more usual areas and environments, in order to avoid the future need for expensive repairs and workovers. This consideration might lead to the use of CRAs for applications where normally low alloy steels are used.

Although the use of Fiber Glass Reinforced Plastic (FRP) has been widely accepted in many surface applications, there is little experience with the materials downhole. Theoretically the material offers excellent opportunities for both Capex and Opex reductions due to its light weight and corrosion resistance over the life cycle. In practice, however, the low pressure rating and the sensitive handling/make-up procedures make application difficult. However, it is perceived that as the experience with and the development of the material increases more applications will be found. As such the API is currently developing specifications for FRP products. At present the use of FRP tubulars is mainly in shallow low pressure water disposal and gaslift wells.




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