As CO₂ emission is becoming an increasing issue in the oil and gas industry and alternative fuels are being investigated, CO₂ capture and H2 production technologies are being developed and improved continuously.

One of the sources of CO₂ emission is the flue gas from sulphur recovery units (SRUs), especially in gas plants where substantial amounts of CO₂ are present in the feed gas to the SRU. This paper studies the options that are available to recover this CO₂ from the SRU and in parallel recover hydrogen, a carbon-free fuel.

To capture CO₂ and recover H₂ form the SRU, modifications have to be made to the SRU to maximize the potential for CO₂ capture and H₂ recovery. This paper presents a case study highlighting these modifications and subsequently evaluates the available technologies for optimized CO₂ capture and H₂ recovery both from a technical and a commercial perspective.

Revamping or replacing the thermal stage of a sulphur recovery unit (SRU) is a common challenge faced by most facility operators, which requires a site-specific design analysis. Replacement could be considered as the thermal stage is a critical equipment cluster with a limited lifespan of typically 15 to 20 years, depending on the operating conditions to which they are exposed.

The stage encompasses the Main Burner, Thermal Reactor, Waste Heat Boiler (WHB), and the first condenser. As facilities age, operators can see a corresponding increase in the frequency of chronic issues around the thermal stage. WHB tube leaks, ferrule damage and refractory lining deterioration, leading to patches on the shell are common challenges.

In an oil refining facility, the sour water can originate from desalters and processing units, such as the Fluid Catalytic Cracker (FCC) or hydrotreaters, as well as amine and sulphur recovery units (SRU), including the Tail Gas Treatment Unit (TGTU). These sour water streams distinguish themselves from a gas processing facility sour water streams through their higher hydrogen sulphide (H₂S) content, the presence of large amounts of ammonia (NH₃) and the much larger volumes that need to be processed.

The processing of these sour water streams in a sour water stripper has been well-documented in literature and it is not the intent of this article to go into design details of these units or what can be done with the stripped water. The focus of this article is to discuss the impact that sour water stripping technology selection may have on the produced sour gas streams, also called sour water acid gas (SWAG).

As well, the article covers the options available to process these gases, considering the current shift in the industry to produce biofuels instead of conventional oil products.

With the growing awareness of the human footprint on our environment also comes the increasing drive to improve and change the way we produce energy and materials. The drive towards a circular economy is also supported by the Paris Agreement (Paris Agreement 2015) in which countries and governments have committed to reducing greenhouse-gas emissions. These developments spur ongoing innovation which also affects the Sulphur Recovery Industry. The main task at hand is: can we reduce or mitigate SO₂ emissions while at the same time adhere to a lower energy input and carbon footprint?

Sulphur recover units are designed to convert highly toxic H₂S into elemental sulphur which is nowadays highly important to produce chemicals and fertilizer. In recent years there has been a trend for more stringent emission specifications with respect to unrecovered sulphur species in the form of SO₂. For many years the World Bank only funded projects where technologies capable of achieving less than 150 mg/Nm? of SO₂ in the stack were employed (World Bank Group 2016). With CO₂, starting to have a financial impact on operations via taxation and trading systems, questions can be raised such as to what extent a reduction of SO₂ emissions renders any benefit. This article seeks to discuss ongoing trends in the sulphur recovery industry as well as address the considerations which arise from the discussion on SO₂ and CO₂ emissions.

The facility in this paper is a gas plant which started operation in 2013 and in the Fort St. John area of British Columbia, Canada. It has a total name plate capacity of 200 MMSCFD sweet natural gas. Liquid carryover of water/MEG/hydrocarbons from the low temperature separator prevented the plant from reaching pipeline water content, hydrocarbon dew point (HCDP) specifications. Initial attempts by the plant’s operations team focused on reduction of contaminant ingress to the refrigeration trains. Despite the improved results, the liquid carryover continued to occur, resulting in off-spec sales gas. Further troubleshooting efforts took a holistic approach and applied multi discipline involvement, equipment sizing, process simulation, along with stream sampling and analysis allowing the team to uncover a list of equipment design flaws. This paper stresses the importance of proper design data hand over from Projects to Operations, understanding the operating envelope of plant equipment, accessibility to plant historian for remote troubleshooting/monitoring, proper MOC (Management of Change) implementation, documentation, and the need for operations/engineering teams training to identify early signs of deviation from optimal process parameters.

Over the past ten years there has been an ever-increasing focus on safety in the Hydrocarbon Processing industry. For those operators who do not already have liquid sulphur degassing capabilities, taking the steps to retrofit this technology into their plant is a positive move forward in safety stewardship. Liquid sulphur is one of the most transported hazardous materials in North America. There is a growing expectation that most of the SRUs in the United States will have to be retrofitted with liquid sulphur degassing in the near future. This eventuality should not be seen as a problematic challenge; the degassing technologies required for safe handling and transportation of liquid sulphur are already available and have a well-established track record in the industry.

The purpose of this paper is to identify the common fundamental design flaws in ethylene glycol (EG) refrigeration plants, the operational challenges associated with them and what can be done to remediate them. The paper is an extension and revision of the “Optimizing Glycol Injection Refrigeration Plants” paper presented at LRGCC in 1991. The use of EG for hydrate inhibition in refrigeration plants to recover NGLs is a common practice. In Canada, the construction of EG refrigeration plants has risen dramatically as a result of the recent economic demand for liquid hydrocarbons. However, as a result of some common misconceptions, many of the EG refrigeration plants built in the past 26 years have fundamental design flaws causing unnecessary initial and continual operation expenditures. This paper, with the help of a comprehensive case study evaluation, aims to highlight theses flaws, their subsequent operational challenges and common recommendations to remediate them.

From time-to-time, operational issues in an SRU are related to the accumulation of liquid sulphur. In the Claus process, sulphur is produced both in the thermal stage and in the catalytic stages. Since the Claus reaction is a chemical equilibrium, the production of sulphur is inhibited if sulphur vapour is already present in the process gas. Therefore, a sulphur condenser is generally used to condense and remove the produced sulphur and ensure continued conversion to sulphur in the subsequent stages).

If the liquid sulphur is not removed properly from the SRU, it can accumulate in the equipment and piping.

Accumulation of the liquid sulphur can impede the flow of process gas in the unit. It can also cause sulphur fires and equipment damage in the presence of oxygen (>10 vol%) and a source of ignition. In addition, the accumulated liquid sulphur can freeze if the plant is let to cool down or can turn into "sulphur concrete" due to poor housekeeping practices. Solid sulphur not only poses the risk of fire, but it can also be difficult and time consuming to remove.

As licensor of SRU technologies, Comprimo, part of Worley (previously, Jacobs), is frequently contacted by clients for support and advice when the SRU is not running properly. The practical experience from sites all over the world is presented in the form of Ten Commandments: these are guidelines for design, construction, choice of equipment, commissioning, and day-to-day operation.

Common problems that were found were related to refractory, burners, reactors and catalysts, condensers, and process control. Some problems are related to design features but many other are due to improper installation of the equipment. Most importantly, attention must be given to day-to-day operation and handling of conditions that are outside of the normal design parameters.

The use of ethylene glycol for hydrate inhibition in natural gas refrigeration plants to recover LPGs is common practice. However, it is important that the ethylene glycol regeneration loop is properly designed to accomadate the operating conditions of the refrigeration process. If this is not the case, there may be issues in the process that can have a significant effect on the plant’s performance. This paper provides a case study on a plant outlining simple changes that can be made in an ethylene glycol regeneration loop to increase liquid production and decrease operating costs.