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TUBING MECHANICAL PROPERTIES Reference 1. Mechanical properties that must be considered

In document Drilling and workover best practices (Page 158-163)


7. TUBING MECHANICAL PROPERTIES Reference 1. Mechanical properties that must be considered

7.1.1. Minimum yield stress.

7.1.2. Ultimate yield stress.

7.1.3. Thermal expansion coefficient.

7.1.4. Young modulus.

7.1.5. Weakening of yield strength with temperatures.

7.2. CRA material and high alloy steel should have anisotropic behaviour.

The derating of yield in relationship the direction of stress shall be considered when anisotropic material is used.

7.3. When reduction in tubing thickness is expected due to corrosion the expected final tubing thickness shall be also considered.

7.4. The connections to be used shall be qualified according to the requirements as set in the Eni-Agip Division and Affiliates procedure

‘Connection Procedure Evaluation’.

• The use of premium connections for tubing is mandatory.

• The use of premium connections for production casing is advised but not mandatory.


P-1-M-7100 7.9.1

Reference List:

‘Completion Design Manual’ STAP-P-1-M-7100

‘Test Procedure for Connection Evaluation’ STAP M-1-M-5006



1.1. In general, the ideal material is determined by the results of corrosion studies carried out prior to the tubing design stage, especially when the severity of the conditions suggest the use of expensive CRA materials.

P-1-M-7100 7.8.1

1.2. The existence, if any, of the following conditions alone, or in any combination may be a contributing factor to the initiation and perpetuation of corrosion:

P-1-M-7100 6.2

1.2.1. Oxygen (O2):

Oxygen dissolved in water drastically increases its corrosivity potential. It can cause severe corrosion at very low concentrations of less than 1.0ppm.

The solubility of oxygen in water is a function of pressure, temperature and chloride content. Oxygen is less soluble in salt water than in fresh water.

Oxygen usually causes pitting in steels.

P-1-M-7100 6.2

1.2.2. Hydrogen Sulphide (H2S):

Hydrogen sulphide is very soluble in water and when dissolved behaves as a weak acid and usually causes pitting. Attack due to the presence of dissolved hydrogen sulphide is referred to as ‘sour’


The combination of H2S and CO2 is more aggressive than H2S alone and is frequently found in oilfield environments.

Other serious problems which may result from H2S corrosion are hydrogen blistering and sulphide stress cracking.

It should be pointed out that H2S also can be generated by introduced micro-organisms.

P-1-M-7100 6.2

1.2.3. Carbon Dioxide (CO2):

When carbon dioxide dissolves in water, it forms carbonic acid, decreases the pH of the water and increase its corrosivity. It is not as corrosive as oxygen, but usually also results in pitting.

The important factors governing the solubility of carbon dioxide are pressure, temperature and composition of the water. Pressure increases the solubility to lower the pH, temperature decreases the solubility to raise the pH.

Corrosion primarily caused by dissolved carbon dioxide is commonly called ‘sweet’ corrosion.

P-1-M-7100 6.2

1.2.4. Temperature:

Like most chemical reactions, corrosion rates generally increase with increasing temperature.

P-1-M-7100 6.2

1.2.5. Pressure

Pressure affects the rates of chemical reactions and corrosion reactions are no exception.

In oilfield systems, the primary importance of pressure is its effect on dissolved gases. More gas goes into solution as the pressure is increased this may in turn increase the corrosivity of the solution.

P-1-M-7100 6.2

1.2.6. Velocity of fluids within the environment:

Stagnant or low velocity fluids usually give low corrosion rates, but pitting is more likely. Corrosion rates usually increase with velocity as the corrosion scale is removed from the casing exposing fresh metal for further corrosion.

High velocities and/or the presence of suspended solids or gas bubbles can lead to erosion, corrosion, impingement or cavitation.

P-1-M-7100 6.2

1.3. Corrosion cell minimum environment 1.3.1. An electrolyte.

1.3.2. An oxidising agent.

1.3.3. A conductive path in the metal.

1.4. Corrosion of steel does take place to the fact that an electrochemical process occurs between an anode area which loose material and a cathode area, on the surface of the metal, in contact with the water.

There are many reasons that this could happen:

1.5. Steel itself is not a pure element but an alloy. The iron carbide, when in contact with pure iron, will form a cell and become the cathode thus causing the anode to corrode.

1.6. The formation of scale in isolated areas can lead to a corrosion cell being formed.

Bacteria, especially slime forming bacteria, can cause corrosion cells to form if only isolated areas are covered.

1.7. The use of different metals in contact is an obvious way to cause a corrosion cell.

1.8. Water effect

1.9. Sulphide Stress Cracking (SSC) P-1-M-7100 6.3.1 1.9.1. The SSC phenomenon occurs usually at temperatures of below 80°C

and with the presence of stress in the material. The H2S comes into contact with H2O, which is an essential element in this form of corrosion by freeing the H+ ion. Higher temperatures, e.g. above 80°C inhibit the SSC phenomenon, therefore knowledge of temperature gradients is very useful in the choice of the tubular materials since differing materials can be chosen for various depths.

Evaluation of the SSC problem depends on the type of well being investigated. In gas wells, gas saturation with water will produce condensate water and therefore create the conditions for SSC. In oil wells, two separate cases need to be considered, vertical and deviated wells:

P-1-M-7100 6.3.1

1.9.2. In vertical oil wells, generally corrosion occurs only when the water cut becomes higher than 15% which is the ‘threshold’ or commonly defined as the ‘critical level’ and it is necessary to analyse the water cut profile throughout the producing life of the well.

P-1-M-7100 6.3.1

1.9.3. In highly deviated wells (i.e. deviations >80o), the risk of corrosion by H2S is higher since the water, even if in very small quantities, deposits on the surface of the tubulars and so the problem can be likened to the gas well case where the critical threshold for the water cut drops to 1% (WC <1%).

P-1-M-7100 6.3.1

1.9.4. The water does not take part in the corrosion process if emulsified in the oil phase. The water phase must wet the metal wall to set up a corrosion cell.

1.9.5. Condition to get water wet walls Gas well with WC < 1 % Vertical oil well with WC > 15 % Horizontal or high deviated wells with WC > 1 %

1.9.6. Using the partial pressure of carbon dioxide as a yardstick to predict corrosion, the following relationships have been found:

• Less than 3psi will not result in corrosion

• Between 3 and 30psi may result in corrosion

• Greater than 30psi will result in corrosion

P-1-M-7100 6.2

1.9.7. The problem of carbon dioxide attack is much worse in gas production than in oil production. In the oil tubular the surface of the steel may be protected by the oil flowing through it. In gas production droplets of saline water will accumulate on the surface of the steel, resulting in small anodes and large cathode causing rapid localised corrosion.

1.10. Hydrogen sulphide

1.10.1. Hydrogen sulphide is soluble in water and acts as a weak acid producing iron sulphide which is cathodic to steel that corrode and tends to form a scale on steel thus further promoting the corrosion reaction.

1.10.2. Free hydrogen is generated by the reaction that may enter the steel structure causing embrittlement. Low hardness material (22 HRC max) shall be used where this phenomena can occur.

1.11. Stress corrosion cracking

1.11.1. Hydrogen sulphide and a tensile stress can act in concert to provide cracks in a susceptible material in particular environment. This form of attack is named stress corrosion cracking (SCC).

The tensile stress can be residual, applied or a combination of the two. The important factor in stress corrosion cracking which makes this form of attack so damaging, is that cracks propagate at much lower values of stress than would cause failure if the corrodent was not present. Stress corrosion cracking can occur in a system which previously has not shown no sign of any corrosion problem, if the operating condition are changed.

1.11.2. The susceptibility to SSC decrease with increasing pH. This decrease starts at a pH of approximately 6 and above a pH of 9.5 SSC generally do not occur.

1.11.3. At temperature above 80°C the SSC is not a concern. That allow to use different material in relationship with the well temperature and depth.

1.11.4. Stress corrosion cracking can occur also in presence of chloride or bromide ions, particularly in hot conditions. These ions can be present in formation water, injection water and brines used as completion, workover and packer fluids.

1.11.5. Certain corrosion resistant alloys (CRA), especially austenitic stainless steel, are susceptible to stress corrosion cracking.


In document Drilling and workover best practices (Page 158-163)