THIS MONTH'S PUZZLER
We're trying to settle a dispute between our on-site contractor and the company designing a vent scrubber for our alkylation spent acid tanks. The design basis is a flow of 3,500 pounds per hour (pph) of a stream containing H2S (about 60 pph), N2, water, O2, 1,3 butadiene, 1,4 pentadiene, acetaldehyde, formaldehyde and other components from the tanks to a caustic scrubber and activated carbon bed (ACB) before going to a stack. This composition seems inaccurate but it's what we have. The gas molecular weight is 29.7 going into the scrubber and 29.1 exiting it. The initial pressure is only 3.2 in. water column (WC); the designer claims the pressure drop through the scrubber will be only 1 in. WC and that the drop through the ACB will be 0.5 in. WC. The designer proposes using a 3-in. schedule-40 carbon steel vent to convey vapor from three spent H2SO4 tanks, a distance of 175 ft.; the same 3-in. pipe will carry fumes 250 ft. to the scrubber and then to the ACB 80 ft. away; the stack is 120-ft high and 24-in. in diameter. The design doesn't include a blower or fan because of the fire risk, which also is why the firm chose steel rather than fiberglass pipe. It also lacks a flame arrestor before the scrubber; the designer says API-2210 doesn't require one because the existing conservation vent will provide sufficient protection. However, the contractor contends the conservation vent must be re-specified for the proposed design changes, the 3-in. pipe won't allow 3,500 pph, carbon steel will corrode and is, in fact, unnecessary, i.e., fiberglass will do because the vent isolates the vent system from flash back (agreeing with API-2210). The contractor also argues the pressure drops in the scrubber and ACB are too low. What do you think? Does the design need changing? If so, how?
START FROM SCRATCH
The vent design definitely is flawed both in mechanics and safety. Mechanically, it simply won't work. For example, it's clear that the "pan-handle" equation was used for the selection of the pipe diameter. Pan-handle assumes an average density and is often acceptable in gas pipeline calculations where the pressure drop is 10% or less. An adiabatic calculation, a little conservative for low pressure, shows choked flow with 3-in. pipe; isothermal, though less conservative than adiabatic by about 10%, probably is acceptable here because it's easier and the pressure drop is small, yielding a low Joule-Thompson effect. Only about 60% of gas will flow though the vent and that's with the given pressure drops through the scrubber and ACB.
Assuming an 0.08-ppm H2S emission, based on Texas limits, 4% caustic in the bed, an irrigation rate of 10 gpm per square foot of packing, 2-in. high-flow packing, and no fouling of the packing, I came up with a 4-ft column with 30 ft of packing, 8-in. inlet and outlet, and a pressure drop of 5 in. IWC. This is a far cry from the proposed column design — and with no safeguards whatever. I would assume at least 10 in. WC for fouling and allow for a packing efficiency of 75%. Also, the pump and spray nozzle should be able to handle as high a flow as possible; I've designed packing for 18 gpm/ft2.
As for the ACB, it's doubtful the bed could be designed to handle, for any length of time, such a concentrated stream with such a variety of hydrocarbons. The bed would breakthrough, rapidly allowing a stream of flammable vapors to exit an open stack. An ACB vendor told me they base their carbon usage rate on benzene. For a gas flow rate of 12,000 pph, they estimated a stream with a 5-ppm benzene concentration would consume 30 lb of carbon per day; a 1.5-ppm stream would use 11 lb. For 2,600 lb of carbon, this gives a life of only 87 days at 5 ppm. The concentration of hydrocarbon in the vent is orders of magnitude higher. This stack should go to a flare. By the way, I would plan for at least 8 in. WC pressure drop through an ACB.
I did a rough calculation for the vent and came up with 6 in. between the tanks and 8 in. to the scrubber. As for the material of construction, carbon steel is probably a bad idea with more than a fraction of water present in the vapor; more than 15-ppm water makes H2S/H2SO4 gas corrosive. Post-weld treated carbon may be enough. I would line the scrubber with a hydrogenated nitrile rubber, or better yet, a fluoropolymer such as PFA, PVDF, or ECTFE. Also, the makeup caustic should be added to a static mixer and strainer prior to the spray nozzle; chilling the caustic improves absorption. Small, delicate items like the spray nozzle should be made of a fluoropolymer to avoid corrosion damage.
Now, let's consider the obvious. Yes, you will need a blower. The presence of flammable hydrocarbons poses a risk requiring a hermetically sealed blower with purged-box controls. The vent design won't work without a blower. Design for a discharge pressure of about 1–5 psig, depending on the limits of the flare header. That's a design head of 2–7 psig for the blower. It's a pity this stream isn't large enough to recover heat by burning it.
Lastly, let's consider the conservation vent. Yes, perform a new calculation for the normal vent. The emergency vent should be adequate.
Dirk Willard, project engineer
Superior Engineers, Hammond, Ind.
OCTOBER'S PUZZLER
We are experiencing water hammer and failure at low-point elbows in our steam-condensate return system. Several old pipe supports have failed. This has become a particular problem in the past few years. The original system ran well with few headaches. The 6-in. schedule-80 pipe carries 75-psig steam condensate back to an old flash tank through a 500-ft pipe. On inspection, I discovered that much of the insulation has been removed and that the header receives condensate from several additional lines, including three 6-in. bare lines running 400 ft, 300 ft and 150 ft. I'm trying to identify the pressure of these condensate lines. It could be 150 psig; the refinery has 400-psig, 150-psig, 75-psig and 25-psig steam. The steam traps, which seem well maintained, are noisy when equipment is running. The condensate return pump at the flash tank is showing signs of wear; it runs nearly continuously and has needed more maintenance than previously. In addition, the backpressure is maintained on the steam return by two pressure transmitters (on the inlet and outlet of the control valve) that wander all over when operating; the operators leave the control valve cocked partially open without bothering with it. What can be done to save this old system? What's wrong with the transmitters?
Send us your comments, suggestions or solutions for this question by September 13, 2013. We'll include as many of them as possible in the October 2013 issue and all on ChemicalProcessing.com. Send visuals — a sketch is fine. E-mail us at [email protected] or mail to Process Puzzler, Chemical Processing, 555 W. Pierce Road, Suite 301, Itasca, IL 60143. Fax: (630) 467-1120. Please include your name, title, location and company affiliation in the response.
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