Hydrotest on Pipeline

Hydrostatic testing has long been used to determine and verify pipeline integrity. Several types of information can be obtained through this verification process.

Ilustrastion for Hydrotest

Source : http://www.enbridge.com/InYourCommunity/PipelinesInYourCommunity/Preventativepipelinemaintenance/Hydrostatic-Testing.aspx

However, it is essential to identify the limits of the test process and obtainable results. There are several types of flaws that can be detected by hydrostatic testing, such as:

• Existing flaws in the material,
• Stress Corrosion Cracking (SCC) and actual mechanical properties of the pipe,
• Active corrosion cells, and
• Localized hard spots that may cause failure in the presence of hydrogen.

There are some other flaws that cannot be detected by hydrostatic testing. For example, the sub-critical material flaws cannot be detected by hydro testing, but the test has profound impact on the post test behavior of these flaws.

Given that the test will play a significant role in the nondestructive evaluation of pipeline, it is important to determine the correct test pressure and then utilize that test pressure judiciously, to get the desired results.

When a pipeline is designed to operate at a certain maximum operating pressure (MOP), it must be tested to ensure that it is structurally sound and can withstand the internal pressure before being put into service. Generally, gas pipelines are hydrotested by filling the test section of pipe with water and pumping the pressure up to a value that is higher than maximum allowable operating pressure (MAOP) and holding the pressure for a period of four to eight hours.

ASME B 31.8 specifies the test pressure factors for pipelines operating at hoop stress of ≥ 30% of SMYS. This code also limits the maximum hoop stress permitted during tests for various class locations if the test medium is air or gas. There are different factors associated with different pipeline class and division locations. For example, the hydrotest pressure for a class 3 or 4 location is 1.4 times the MOP. The magnitude of test pressure for class 1 division 1 gas pipeline transportation is usually limited to 125% of the design pressure, if the design pressure is known. The allowed stress in the pipe material is limited to 72% of SMYS. In some cases it is extended to 80% of SMYS. The position of Pipeline and Hazardous Material Safety Administration (PHMSA) is similar. Thus, a pipeline designed to operate continuously at 1,000 psig will be hydrostatically tested to a minimum pressure of 1,250 psig.

Though codes and regulatory directives are specific about setting test pressure to below 72% or in some cases up to 80% of the SMYS of the material, there is a strong argument on testing a constructed pipeline to “above 100% of SMYS,” and as high as 120% of SMYS is also mentioned. Such views are often driven by the desire to reduce the number of hydrotest sections, which translates in reduction in cost of construction. In this context, it is often noted that there is some confusion even among experienced engineers on the use of term SMYS and MOP/MAOP in reference to the hydrotest pressure.

It may be pointed out that the stress in material (test pressure) is limited by the SMYS. This is the law of physics, and is not to be broken for monetary gains at the peril of pipeline failure either immediate or in the future.

Metal stress diagram.

Source: http://www.pipelineandgasjournal.com/pipeline-hydro-test-pressure-determination?page=show

Often there is argument presented that higher test pressures exceeding 100% of the SMYS will increase the “strength” of the material and will “stress relieve” the material. Both arguments have no technical basis to the point they are made. We will briefly discuss both these arguments here:

1. Higher test pressure will “increase the strength.” As the material is stressed beyond its yield point, the material is in plastic deformation stage, which is a ductile stage, and hence it is in the constant process of losing its ability to withstand any further stress. So, it is not increasing in strength but progressively losing its strength.
2. The second argument of “stress reliving” is linked with the “increase the strength” argument. The stress relief of material is carried out to reduce the locked-in stresses. The process reorients the grains disturbed often by cold working or welding. The stress relief process effectively reduces the yield strength. Thus, it does not “strengthen” the material. Note: It may be pointed out that a limited relaxation of stresses does occur by hydro testing, but the test pressure should be less than the material’s yield point.

Another point to note here is that there is a stage in the stressing of the material where strain hardening occurs and the material certainly gains some (relative) hardness, and thereby, strength. This happens as necking begins but, at that point, unit area stress is so low that the strength of the material is lost and it remains of no practical use, especially in context with the pipe material we are discussing.

Returning to the subject of pressure testing and its objectives. One of the key objectives of the testing is to find the possible flaws in the constructed pipeline. The test develops a certain amount of stress for a given time to allow these possible flaws to open out as leakages.

Source: 

http://www.pipelineandgasjournal.com/pipeline-hydro-test-pressure-determination?page=show
https://riomardhian.wordpress.com/2015/02/

Dega Damara Aditramulyadi

Student ID : 15512046

Course      : KL4220 Subsea Pipeline

Lecturer   : Prof. Ir. Ricky Lukman Tawekal, MSE, Ph. D.

                  Eko Charnius Ilman, ST, MT

Ocean Engineering Program, Institut Teknologi Bandung

http://www.ocean.itb.ac.id/en/