Oct-2009

Revamping hydrogen and sulphur plants to meet future challenges

Revamp opportunities for hydrogen and sulphur plant operations in the era of clean fuels production offer significant benefits for refiners

Adrienne Blume, Patrick Christensen, Brett Goldhammer and Thomas Yeung
Hydrocarbon Publishing Company

Article Summary

Around the world, increasing demand for clean fuels has led refiners to alter operations for the production of low-sulphur gasoline and diesel. Furthermore, refinery operators are purchasing larger quantities of heavier, sourer crudes to take advantage of a discount over light, sweet crudes.

To support fuel and crude supply trends, the installed capacity of hydroprocessing technologies (ie, hydrotreating and hydrocracking) has increased steadily in recent years. FCC technology — the capacity of which has been on a similar upward trend — also plays a key role in clean fuels production and is considered a major emitter of H2S and SOX.

The increases in these three processing technologies coincide with a five-year average increase in both refinery on-purpose hydrogen production (and recovery) and sulphur processing capacity. Figure 1 indicates worldwide growth in these areas in terms of refinery production capacity since January 2005. Worldwide refinery hydrogen production capacity has grown at an average annual rate of 2.15%. Average annualised growth for worldwide sulphur processing capacity since January 2005 was pegged at 2.9%.

In the past, the hydrogen production unit and the sulphur plant had been considered supporting units for the major refining processes; however, as hydroprocessing capacity continues to expand along with the processing of heavier crude, the impact of the operations of the hydrogen unit and the sulphur plant has grown. Modification and expansion of refinery hydrogen production and sulphur plants via revamp and retrofit projects will be necessary for meeting future process requirements while maximising the value of current plant configurations and assets. The following is intended to provide an overview of available technologies and operational goals that should be considered when revamping the hydrogen plant and/or sulphur recovery/production plant in a modern refinery.

Hydrogen plant revamps
The hydrogen production facility can now be considered a major component of the refinery and, like any utility, maximising the economics of producing and consuming hydrogen in the refinery affects the overall success of the plant. Technology for the production of refinery hydrogen is currently dominated by the use of steam reforming of natural gas or other light hydrocarbons. Figure 2 shows a refinery hydrogen network.

The revamp of an existing hydrogen plant is considered the cheapest way to add 10–30% capacity.1 A number of potential revamp projects, listed in order of increasing investment requirements, can be implemented to augment capacity: employ hydrogen management; increase reformer firing; improve PSA recovery; reduce steam-to-carbon ratio; add CO2 recovery; install a low-temperature shift; and add a pre-reformer or post-reformer.2 However, several important constraints are involved in such revamps; namely, minimum hydrogen product pressure, hydrogen purity, process cooling duty, availability of plot space, available down time for revamps, utilisation of export steam, availability of other utilities, safety, and pollutant emissions.3 In addition, the debottlenecking and expansion of existing hydrogen plants depends on limitations to the reformer, such as tube metal temperature, burner heat release, catalyst bed pressure drop, induced draft/forced draft fan capacity and pressure swing adsorption (PSA) capacity.4 The relative cost and incremental hydrogen gain of potential revamp activities is summarised in Table 1.

Hydrogen management and/or recovery
Implementing hydrogen management is often the first step to revamping and/or improving a refinery’s hydrogen network. Hydrogen management using pinch technologies and mathematical modelling will result in improved process efficiency, reduced energy consumption, lower operating costs, and improved integration of hydrogen-producing and -consuming units. One drawback to hydrogen management is that the available capacity gain is constrained by the limitations of the current system. Hydrogen management services are becoming more prevalent as refiners look for economical ways to meet hydrogen demands. These offerings primarily take a phased approach to balance use of refinery hydrogen (often by hydrogen pinch techniques), to identify potential projects for improvement (new units, revamps, recovery schemes and so on) and to implement or evaluate changes.

As an example, engineers from Indian Oil Corporation discussed a novel in-house methodology to improve hydrogen management in a refinery. The process begins by defining the hydrogen network in the refinery: hydrogen production units (steam methane and/or naphtha reformers); purge gas and offgas streams as recovery sources (for instance, a catalytic reformer); and major hydrogen consumers (hydrotreating, hydroprocessing). The engineers identified the opportunity to limit spill-over hydrogen — excess gas that allows for continued operation of hydroprocessing units during a hydrogen supply disruption — that is routed to the fuel gas system during normal operations. Following the evaluation, two strategies were implemented to improve the use of spill-over stream: integrate all of the hydrogen-producing and -consuming units; and eliminate the spill-over stream by utilising an offsite storage facility and process optimisation.⁵

In many distribution systems for refinery hydrogen, hydrogen supply is cascaded through a number of hydroprocessing units in which higher-purity, high-pressure hydrogen-consuming units pass their purge gases to lower-purity, lower-pressure units. As demand for hydrogen increases, the optimum cost-effective recovery of gas streams with marginal hydrogen content is becoming more imperative.^6,7 Generally, streams with less than 50% hydrogen are routed to fuel. Streams of greater than 50% hydrogen content, with sufficient pressures, are routed to various purification units like PSA, membrane and cryogenic systems for recovery. The cost of hydrogen recovery can be almost half the cost of production.

For successful hydrogen recovery, the heating value of the fuel gas after hydrogen removal, the impact on the burners, the location where recovered hydrogen enters the network, and the impact on the whole system must be considered.⁸ Depending on the pressure and purity of residual hydrogen, recovery followed by purification might be an option to supplement production from steam reformers. The primary sources for hydrogen recovery are either high-pressure purge loops or low-pressure, high-purity off-gas streams. As a general advantage, recovering hydrogen that would be routed to the refinery’s fuel gas system will inherently increase the heating value of the fuel gas. Table 2 provides a selection guide to hydrogen recovery processes.⁹