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May-2015

Unload the SRU to reduce plugging problems and operating costs

A crude oil refinery may need additional sulphur recovery capacity for any of a combination of reasons:

Richard Kolodziej, Wood Mustang Group
Mark Anderson, ThioSolv LLC

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Article Summary

•  Increased crude rate, and/or
•  More use of higher sulphur, lower priced crudes, and/or
•  Hydrotreating heavier and more refractory streams, and/or
•  Increasing hydrotreating severity to meet tighter sulphur specs of some products.

There are still many parts of the world where refiners still face the prospect of dealing with the effects in many of these areas.

Although most of these effects have already occurred and been accommodated in the US and the EU, a recent regulatory change, the reduction in sulphur spec on marine diesel, still means sulphur recovery effects from the latter issues in the US and Canada. In the last few years, the US EPA lowered the Non road, Locomotive, Marine (NRLM) diesel sulphur spec to 500 wppm and now to even 15 wppm for most streams. In the past, marine diesel made in the US provided the outlet for the diesel boiling range streams with higher endpoints, and containing the more refractory cyclic sulphur and nitrogen compounds, but no more. This year the International Maritime Organization (IMO) lowered the sulphur limit in marine diesel for ships in emission control areas (ECA) along the shorelines of the US and Canada from 1.0% to 0.1%. So, there are still some, but smaller incremental effects of more domestic distillate desulphurisation.

For all four scenarios noted above (except for a crude capacity increase with the same crude type), the ratio of incremental ammonia (NH3) to incremental H2S production will be much higher than the refiner’s current operation.

This can be explained as follows:
• Feed streams to hydrotreatment will have higher N/S ratios as boiling range and aromaticity increase. So, heavier and/or more refractory streams will necessarily result in more denitrogenation as sulphur is removed.
• Ratio of HDN to HDS increases as severity of hydrotreatment increases. At 90% HDS, the incidental HDN has typically been only 20-30%. But to reach <10 ppmw S material, HDS must be increased to >99%, requiring conditions that allow hydrogen to attack the most refractory C-S bonds, those in polycyclic, heterocyclic sulphur compounds. Those conditions also allow H2 attack on analogous C-N bonds, increasing HDN to >90%. Consequently, incremental NH3 yield will be 200-350% while incremental H2S from the same feed may only be only 10-20%.

A sometimes under-appreciated result is that the feed to Sulphur Recovery Unit (SRU) changes not only quantitatively, but also qualitatively. Although H2S is only slightly soluble in water, ammonia produced by HDN dissolves readily in the was water phase and in turn, dissolves a roughly equimolar amount of H2S in the water so it reports to sulphur recovery as sour water stripper gas (SWSG) instead of amine acid gas (AAG). An increase in ratio of NH3 to H2S production therefore results in a higher ratio of sulphur in SWSG to sulphur in AAG.

The Claus Plant load from a ton of H2S in SWSG is much greater than from a ton of H2S in AAG. In the Claus Plant equipment, only the sulphur pumps and piping are sized for the sulphur rate; the rest of the equipment (heat exchangers, reactors, etc.) and piping are all sized for the gas traffic through the unit.

As a shorthand means of quantifying the capacity of a given Claus unit for feed compositions other than that for which it was designed or for quantifying the Claus load imposed by a specific feed composition, ThioSolv, Inc. has coined the term “H2S-equivalent rate” to express both capacity and load in the same units relating to gas flow through the Claus, or more precisely, the pressure drop resulting from it. ThioSolv defines the “H2S-equivalent rate” of a feed stream as the flow rate of pure H2S feed that would result in the same pressure drop as the subject feed stream. For each component of the feed stream, an “H2S-equivalent Factor” has been calculated as the gas flow produced, based on simplified stoichiometry, from feeding one mol of that component to Claus, divided by the gas flow produced from one mol of H2S and then adjusting by the square root of mol weights of the respective product gases.

The table above lists molar H2S-equivalent Factors for common components of Claus feed. The H2S-equivalent load is the sum of the molar flow of each feed component times its respective H2S-equivalent Factor. The H2S-equivalent Factor for a feed stream is of course the H2S-equivalent load so calculated, divided by the molar rate of contained H2S:

One general conclusion that jumps out is the importance of minimising the amount of hydrocarbon in the feed to Claus. One volume of butane takes up the Claus capacity for almost twelve volumes of H2S. And the operations effects of hydrocarbons to the Sulphur Plant are known by those familiar with the process: high air demand, high H2S/SO2 ratio, low recovery, high recycle from tail gas treating, and sometimes excess SO2 in the incinerated tail gas.

Compare the flow of tail gas from Claus produced from a mole of H2S fed as pure H2S to that fed as SWSG:

Pure H2S                        Total               H2S-eq
                                        Flow              Factor
Reaction:                          H2S + O2 + N2 ==> H2O + N2 + S            Gas volumes:                    1    0.5      1.9        1       1.9    1       2.9     1.0*
*by definition

The gas traffic from one unit of H2S (neglecting the S species because most of that condenses out early in the process) is about 2.9 volumes of gas per volume of H2S. (Amine acid gas commonly contains other components, including CO2, water vapour, and minor amounts of hydrocarbon, that increase its H2S-equivalent factor to 1.05-1.10.)

The wash water injected into the reactor product condensers of higher severity hydrotreaters to minimise the formation of ammonium salts dissolves the ammonia and absorbs a roughly equimolar amount of H2S. When this sour water is stripped, the product SWSG has nominal equimolar concentrations of H2S, NH3, and water.

Sour Water Stripper Gas (SWSG):                                                                                               Total            H2S-eq
                                             Flow           Factor
Reaction:    H2S + O2 + N2 ==> H2O + N2 + S            Gas volumes:      1       0.5   1.9            1  1.9     1     2.9      1

                   NH3 + O2 + N2 ==> H2O + N2
                   1       0.75  2.8       1.5     3.3           4.8    1.7         
                    H2O     ==> H2O
                   1                1                                    1.0      0.3
                                                                           8.7      3.0

The volume of gas produced from one unit of H2S in SWSG is 8.7 volumes of gas per volume of H2S, or three times the volume from the H2S alone. And the ammonia must be reduced to N2 to mimimise ammonium salt formation downstream in the SRU.

So, the capacity effects of more SWSG fed to the Claus Plant add up quickly. Referring to the table below, a Claus Plant that is fully loaded with 90 tpd of AAG H2S and 10 tpd of SWSG H2S of 124 tpd of pure H2S, not counting tail gas treater recycle. The incremental Claus load from a project that increases the production of H2S by 15 tpd (15%) and a seemingly small increase in NH3 of 2.5 tpd (50%) represents an H2S-eq equivalent load increase of 30 tpd =25%.


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