Abstract

Saudi Aramco, like other operators with lean feed acid gas containing benzene, toluene and xylene (BTX) has dealt for years with chronic Claus catalyst deactivation, low sulphur recovery and frequent shutdowns to replace catalyst. After completing an exhaustive process selection study to identify the most cost effective solution to the problem, the company proceeded with installation of regenerable activated carbon beds upstream of the sulphur recovery units (SRUs) to remove aromatics contaminants before they reach the converter beds.

Saudi Aramco completed construction of seven BTX removal units to treat acid feeding downstream sulphur plants in December 2005. Commissioning took place in the spring of 2006. This paper discusses design issues, start-up and commissioning experience for the units, their performance and impact on the downstream Claus catalyst.

In brief, catalyst deactivation has been virtually eliminated. This has set the foundation to allow us to revamp the units to achieve higher recovery, which would not have been possible until catalyst deactivation had been resolved.

This paper was originally presented at the 57th annual Laurance Reid Gas Conditioning Conference in Norman, Oklahoma, February 25–28, 2007. However, it has been updated to reflect the most recent operating experience from the carbon units.

Acronyms and Key words:

  • BTX - benzene, toluene and xylene

  • CBU - Carbon Bed Unit

  • MTZ - Mass Transfer Zone

  • PCD - Pressure Control Drum

  • SRU - Sulphur Recovery Unit

  • Associated Gas, Sour Gas, Acid Gas

Introduction

For years Saudi Aramco faced rapid and chronic Claus catalyst deactivation induced by aromatics in feed acid gas at two of its largest gas plants. How these difficulties arose and were eventually solved is a story that began in the late 1970s. Up until that time solution gas produced with crude oil was flared. This is referred to as associated gas. To make use of this resource, the Kingdom directed Saudi Aramco to gather and process this gas into fuel gas and NGL products. The capital spending program to accomplish all this was called the Master Gas System.

Selecting an amine to treat sour associated gas to a ¼ grain H2S per 100 SCF pipeline specification was one of many design challenges. It's easy to forget sometimes how far the gas processing industry has come in the last thirty years in terms of understanding the capabilities and limitations of various amines. At that time, process simulators were in their infancy and the extensive database of thermodynamic and kinetic properties for many amines that we take for granted today did not exist. The selection process that led to choosing Diglycolamine® or DGA is nicely described in an article by Huval and van de Venne1. Their paper mentions a concern that DGA would be prone to co-absorption of heavy hydrocarbons and that this could lead to poor sulphur product quality. It also describes how fuel gas spargers were installed in the bottom of the rich amine flash drum to mitigate this. Because of its other advantages though, primarily the ability to treat sour gas at high temperatures, it was selected for the Master Gas System.

Because DGA removes essentially all H2S and CO2 from treated gas, the H2S:CO2 ratio in acid gas is determined by the ratio of these components in the sour gas. At Saudi Aramco's Shedgum and 'Uthmaniyah gas plants, this results in an acid gas composition that ranges between 17% and 30% H2S. For these low levels of H2S, a reaction furnace bypass is necessary even after preheating the air and acid gas in fired preheat furnaces. About half the acid gas bypasses the furnace. Hydrocarbons co-absorbed by the DGA solution and transferred to the acid gas make their way via the bypass to Claus catalyst in the converters (Figure 1).

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