Claus waste heat boiler economics Part 2: mechanical considerations

The design of a cost effective waste heat boiler faces many, often opposing factors affecting the performance and reliability of the exchanger.

Optimized Gas Treating Inc

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Article Summary

The Claus waste heat boiler (WHB) runs under quite harsh operating conditions, has serious reliability challenges, and is one of the most fragile equipment items in the sulphur recovery unit (SRU). It not only provides heat recovery from the thermal section, but it also affects the unit’s hydrogen balance and COS levels through recombination reactions.

Part 1 of this two-part series (see PTQ, Q1 2019) discussed general process considerations including the effects of tube length, pressure drop, and COS/H2 reactions on sulphur recovery. One of the main concerns was exothermic recombination reactions and how they affect SRU performance in terms of hydrogen make, COS creation, and sulphur recovery:

H2 + ½ S2 ⇌ H2S
CO + ½ S2 ⇌ COS

Part 2 focuses on determining the heat flux and tube wall temperature profiles along the length of the boiler. This is aimed at understanding the particularly important area near the critical tube-to-tubesheet joint where WHB mechanical failures frequently occur. Also relevant are boiler tube corrosion rates and subsequent boiler failure together with the cost of its mitigation. The recombination reactions are exothermic. They increase both the process fluid and tube wall temperatures, as do the species shifting between the S2, S6 and S8 allotropes of sulphur. Radiative heat transfer coupled with the exothermic recombination reactions collectively increase the peak heat flux at the front of the boiler well above predictions from models that ignore or discount some (or all) of these factors.1 Greatly elevated tube wall temperatures well downstream of the area of protection provided by ceramic ferrules for the higher mass velocity cases is demonstrated, lending theoretical support to documented failures in the industry. In this article, tube wall temperatures, and heat flux predictions from the model are examined down the length of the tubes along with the implications of sulphidic corrosion and the resulting effect on boiler tube life and SRU reliability economics examined with this new information.

Case study
The following case study is a continuation from Part 1 and is a typical 125 lt/d sulphur plant (see Figure 1) with two converter stages processing both amine acid gas (AAG) and sour water acid gas (SWAG). Table 1 shows the conditions of these two acid gas feed streams. The WHB was sized in Part 1 by fixing the process-side mass flux, the tube size, and the process outlet temperature. The tube count and tube length were adjusted to meet target specifications. The results were obtained using the kinetic heat transfer and chemical reaction rate based SulphurPro SRU simulator within ProTreat Version 6.4.

Table 2 shows values for other design parameters assumed for this application of the model. The boiler produces 350 psig saturated steam from preheated boiler feed water.

Heat flux, tube wall temperature, and corrosion implications

Heat flux is a very important factor in the reliability, life cycle cost, and the safe long term operation of the WHB. Heat flux varies greatly along the tube length; it is highest at the process inlet and decreases as the process gas cools. In terms of reliability, it is our experience that failures tend to become more common with heat fluxes exceeding 50000 Btu/ft2·h. At elevated heat flux, problems with steam blanketing on the utility side are more common. Locally high heat flux values can result in local steam blanketing which, in turn, can result in locally higher tube wall temperatures and increased corrosion rates. A host of other factors such as tube pitch and orientation also play into the likelihood of steam blanketing; these are discussed elsewhere.2 The life cycle cost of a WHB depends greatly on the corrosion rate of the boiler tubes caused by high heat flux and high tube wall temperatures. Tube wall temperature together with the concentration of H2S present correlate directly with the sulphidic corrosion rate.2  Figures 2, 3 and 4 show the heat flux and tube wall temperature profiles along the length of the exchanger tubes for 1.5in, 2in, and 3in diameter tubes, over a range of mass fluxes. Tube lengths have been determined so that the process gas just reaches 550°F (288°C) at the exit from the tubes.

Each curve shows a wave approximately one-third of the way along the boiler tubes. This is caused by the sulphur species shifting from S2 to S6 and S8 (sulphur redistribution), which are exothermic polymerisation reactions. Note that the heat flux considered here does not account for thermal protection provided by ferrules or for the enhanced heat transfer effect of eddies at the ferrule exits. Eddies in the process gas flow as it exits the ferrules can cause the heat flux to be amplified several times for a short distance.2 As the mass velocity is increased at a constant boiler tube size, the peak heat flux and tube wall temperature both increase at the front of the tubes. This is where almost all failures from sulphidic corrosion occur. Tube wall temperature ties directly into the sulphidic corrosion rate. As the mass flux through the boiler tubes increases, the tube wall temperature increases by approximately 130°F (72°C), which translates directly into higher sulphidic corrosion rates.

The predicted corrosion rates shown in Figure 5 for two mass fluxes in a 2in tube were determined from our digital correlation of the well-known Couper-Gorman curves, reproduced from the correlation here as Figure 6.

At constant mass flux, Figures 2-4 show that larger boiler tubes tend to produce higher tube wall temperatures. Corrosion concerns tend to increase at tube wall temperatures greater than 600-650°F (315-343°C). For this study, the tube-wall temperature at the front of the boiler tubes is generally approaching this temperature range for mass fluxes between 
2 and 3 lb/ft2·s. The service life of the exchanger is directly determined by the corrosion rate, and the life cycle cost is a strong function of service life.

Looking at how sulphidic corrosion occurs through the length of the exchanger, the higher mass flux case has significant corrosion rates through the first five feet or so of the tubes. Figure 5 shows how the corrosion trends through a 2in outside diameter tube at 2 and 5 lb/ft2·s mass flux. The corrosion rate increases by almost a factor of four at the higher mass flux.

Life cycle cost and economics
There are two ways that Claus WHBs cost the operator:
• Capital cost incurred when the plant is built: ‘pay me now’ 
• Operating and maintenance costs that are incurred: ‘pay me later’.

Capital cost is relatively straightforward to estimate. For the purpose of this article, the capital costs were calculated based on ratioed in-house budgetary equipment quotes, then applying an overall installation factor of five to place the estimates on a US Gulf Coast battery limits installed cost basis. Consideration of a steam drum was included in the cost estimate.

Normal operating and maintenance (O&M) costs that run day to day were assumed to even out across the various cases. The main distinguishing parameter that affects O&M costs is replacement frequency, and whether a planned or unplanned outage was taken. The replacement cost was estimated to be a new exchanger purchased in the future year plus a variable ‘outage’ cost component. If a particular hydrocarbon producing plant happens to be sulphur constrained, then an outage can result in quite significant lost profit opportunity based on an advantaged feedstock margin. In many cases, the O&M cost may be considerably less if, for example, only refractory work or retubing were conducted. The results here are intended to be illustrative, and it is the relative difference between the lifecycle costs that is important, not the absolute values.

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