Feb-2016

Tube rupture in a natural gas heater

Dynamic simulation supports the use of a pressure safety valve over a rupture disk in the event of a tube rupture

HARRY Z HA and PATRICK STANG
Fluor Canada Ltd

Article Summary

A fast pressure surge will occur during the tube rupture of a shell and tube exchanger, where a big pressure difference exists between the tube (high pressure) and shell (low pressure) sides. The pressure rise can be so fast that a conventional pressure safety valve (PSV) may not be able to open properly to accommodate the pressure surge. Dynamic simulation of tube ruptures in a shell and tube exchanger generates the time related pressure and temperature profile for the exchanger when the rupture happens. The results can provide a solid basis for process design, whereby whether or not a rupture disk should be used instead of a PSV if the pressure rise is too quick for the PSV to open. A dynamic simulation for tube rupture analysis of a natural gas heater is conducted in this study. The heater is a shell and tube exchanger, which utilises low pressure steam (shell side) to heat the tube side high pressure natural gas (113 barg). A detailed Hysys simulation model was built to reflect the external and internal configurations of the exchanger.

A tube rupture scenario was set up by assuming one full bore rupture at the back side of the tube sheet (per API Std 521 – 5.19.3). The dynamic simulation model was validated with the heat and material balance before running the case scenarios. The pressure and temperature profile, as well as the relief load, were recorded versus time during the event. The results support the process design of a spring loaded PSV as a means of protection of heat exchanger shell side instead of the rupture disk, in the case of tube rupture of the natural gas heater.

Shell and tube exchangers are widely used in the oil, gas, and petrochemical industries. Depending on the application, the tube side fluid pressure can be significantly different from the shell side pressure. According to ASME Sec. VIII Div. 1, a vessel has to be hydrotested at 130% of its maximum allowable working pressure.1 This would allow for design pressure excursion by 130%, hence the 10/13th rule. Based on this requirement, if the design pressure of the low pressure side is inside the envelope of 10/13th of the high pressure side, no extra protection on the low pressure side is warranted. For systems where the low pressure side is below the 10/13th criteria, the tube rupture scenario can be mitigated by increasing the design pressure of the low pressure exchanger side, and/or assuring that an open flow path can pass the tube rupture flow without exceeding the stipulated pressure, and/or providing pressure relief (API Std 5212). However, for a heat exchanger with a large pressure difference between the high pressure and low pressure side, increasing the low pressure side’s design pressure can be expensive and evaluation of a tube rupture scenario is required.

When a tube rupture occurs within a heat exchanger, high pressure fluid expands into the low pressure side through the ruptured tube bore and creates a pressure surge on the low pressure side. Depending on the nature of the fluids on both sides, the pressure surge on the low pressure side can be instantaneous. When both tube and shell sides are in liquid service, the pressure surge is faster than the response time for a PSV to open so that a rupture disk has to be installed.3 From an operation and maintenance point of view, it is less desirable to use rupture discs for a service since rupture disks require more maintenance and the relief is also uncontrollable once it is broken. However, when both shell and tube sides are in vapour service, a PSV might have enough response time to react to the pressure surge caused by tube rupture, considering the compressibility of vapour.

This study will demonstrate such a case by dynamic simulation, where the high pressure natural gas in the tube side is heated by low pressure steam on the shell side. The dynamic simulation will capture the pressure rise profile over time, which provides a solid basis to support the installation of a PSV instead of a rupture disk for a tube rupture scenario in a natural gas heater.

System description and model setup
The system studied here is a typical natural gas heater in the inlet line of a LNG plant. The heat exchanger is a TEMA BEU type exchanger with high pressure natural gas passing through the tube side and low pressure steam condensing on the shell side. High pressure natural gas enters the tubes at 112.7 barg and 3.2°C, and leaves the exchanger at 80°C. Low pressure steam condenses on the shell side at 3.5 barg and 147°C. The exchanger operates under no-flooding condition. The condensate is drained to a condensate pot and leaves the system on level control (see Figure 1). The intended exchanger configuration includes a PSV (6R8) with a set pressure of 5.5 barg installed on the steam inlet line.

The BEU heat exchanger is the ideal choice for heating low fouling fluids like natural gas. The U-Tube bundle is attached to a single tube sheet, allowing the tubes to expand and contract freely under the influence of temperature variations. The tube bundle is removable and allows cleaning of the outside surfaces of the tubes. Lateral baffles are inserted to provide sufficient residence time for segmental heating. The steam flows horizontally from one segment to the next. The studied exchanger has eight baffles, which separate the shell side into nine horizontal sections (see Figure 2).

The shell side of the exchanger is modelled as nine separate vapour sections to match the baffled shell segments of the exchanger design. These vapour sections are modelled as horizontal cylinders in the dynamic model. The segment length matches the distance between two baffles, and the segment diameter is calculated based on the total shell side volume. The heating steam is assumed to be evenly condensed as it passes through the nine baffled segments of the shell. The steam may condense unevenly as it passes through each segment. However, the impact of condensing load distribution on tube rupture simulation is insignificant since the heat exchanger operates under no-flooding condition. The condensed steam is removed from each segment by using flow controllers to simulate the operation of the exchanger in a no-flood condition, with the condensate being routed to the condensate pot.

A control valve set to 100% open is used to simulate the tube rupture event. The valve is sized to allow the maximum (choked) flow from the high pressure tube side into the low pressure shell side. The maximum flow is calculated from an assumed orifice. The orifice has the equivalent open area that is twice the internal cross-sectional area of one tube to allow for the entrance of the high pressure fluid through a single tube rupture (per API STD 521 - 5.19.3).

Tube rupture dynamic runs and simulation results
The dynamic simulation model is tuned to match the steady state simulation results before running the tube rupture scenario. Once the dynamic simulation reaches the steady state condition and consistent results have been established (key operating parameters become constant with time), an event scheduler is initiated to run the tube rupture case. The tube rupture case considers a sharp break in one tube and the tube rupture is assumed to occur at the back side of the tube sheet (API Std 521 – 5.19.3).

The following tube rupture assumptions are programmed into the event scheduler:
a) One tube ruptures at one second integration time.
b) All flow control valves for diverting segmental flow stay in position when the tube rupture happens (assume the steam passing across the shell side with the same flow pattern as normal).
c) Back flow of the high pressure natural gas to steam is not allowed when the shell pressure reaches the steam supply pressure and, therefore, steam flow is stopped at this condition. This is a conservative approach for PSV relief load calculation.