ABSTRACT

Hydrogen production in a heavy oil Upgrader is one of the most important unit processes, because it provides the hydrogen and steam required for heavy oil Upgrader process facilities. These units have large heat exchanger trains which are under severe conditions such as high CO2 content and high temperatures. Therefore, the equipment in this highest impacted service are designed with highly corrosion resistant materials such as UNS S30400 and UNS S316000. However, sometimes these materials are suitable for the severe conditions of the shell side but not for the condition on the tube side. This unsuitability, in this case, is primarily due to the boiler feed water, specifically the water's chlorine content. Even in low concentrations, chloride in the high temperature conditions in contact with austenitic material can cause a component to fail catastrophically. In addition design condition such as stress concentration devices and inappropriate commissioning procedures can make the austenitic steel tubes prone to fail too early. This paper shows the experience of failure of a heat exchanger due to chloride stress corrosion cracking (SCC) in the Upgrader facility.

INTRODUCTION

The design of a heat exchanger for Venezuelan Heavy oil Upgrader Hydrogen unit process takes in account the material selection for corrosive service. This is considered the process side due to the high content of CO2, however the details of chemical characteristics of tube side were not considered. Therefore, the use of austenitic stainless steel (UNS S30400) was used to build the highest impact heat exchanger of the post reaction train. This train, shown in the Figure 1, was not suitable. Eight weeks after startup a failure was detected in one of the train of hydrogen unit process called BFW Preheater No. 1. Twelve weeks later, the second train, called BFW Preheater No. 2 also failed. After the first failure, an exhaustive investigation of the commission process was requested in order to evaluate neutralization and preservation procedures for both BFW Preheaters. The first hypothesis established that the commissioning process could be the root cause. The investigation which followed showed that all required procedures in the project specification were followed and accepted without observation.

After the failure was detected, a detailed inspection was done because the cause of the failure was unknown. A video boroscope inspection was performed an indication was observed in the internal side of the tube, as indicated in Figure 2. Additionally an extensive quantity of white deposit was detected in the tube side of the equipment as shown in Figure 3. The composition of the white deposit is shown in Table 1.

Due the operational requirements, the plant should have started up again; consequently the heat exchanger No. 1 had to be put in service as soon as possible. Due to the high leakage, a total of 42% of the tubes were plugged, which led to the construction of a new bundle. After 12 weeks in operation, the equipment No. 2 subsequently failed. The primary visual inspection also showed the same indication found in the heat exchanger No. 1.

The new heat exchanger's tube was made from low carbon austenitic stainless steel, UNS S304001, and was installed three months after the first failure. The plugged heat exchanger was sent to shop to be retubed and the sample of a failed tube was taken for metallographic analysis. A sample is shown in Figure 4.

After 6 weeks of operating this new equipment, a new failure was detected. Despite the fact that this new equipment and the other new bundle installed in Train 2 were constructed in UNS 30403, both failed again. There were a total of four failur

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