Multimillion-Dollar Capital Cost Reductions Achieved At Natural Gas Plant Through Intelligent Design

Gas plant operators can unlock substantial value by designing the acid gas removal unit and the sulphur recovery unit as an integrated block, says Matthijs de Oude, Manager Design Integration – Gas Processing, Shell Global Solutions, in an interview with Impact.

De Oude explains that the industry is increasingly developing natural gas fields containing contaminants such as benzene, toluene, ethylbenzene and xylene (BTEX), and organic sulphur compounds such as carbonyl sulphide, carbon disulphide and mercaptans. The implications for gas plants are profound, as they require ever-more-sophisticated gas processing technologies to bring the product up to pipeline specifications.

Moreover, the quality of the acid gas challenges the sulphur recovery unit, which sits downstream of the acid gas removal unit.

There is often the tendency to source these units independently, but de Oude says that there is substantial value to uncover when the design considers the impact that the acid gas removal unit can have on the sulphur recovery unit. He cites the example of a plant that was being designed to process 67 MNm3/d of non-associated gas. The raw natural gas contained substantial concentrations of carbon dioxide, hydrogen sulphide, heavy hydrocarbons and organic sulphur compounds.

The original design of the reference plant had four parallel acid gas removal units using methyl diethanolamine. The resultant acid gas for routing to the sulphur recovery units would contain approximately 34 mol% hydrogen sulphide, 600 ppm BTEX and hundreds of parts per million of carbon disulphide and mercaptans.

“However,” says de Oude, “because the hydrogen sulphide content of the acid gas in the reaction furnace was relatively low, the temperatures were insufficient for BTEX destruction.”

He continues, “To overcome this, the owner had considered several options, including high-pressure steam preheating of the acid gas, indirect fired heating of the combustion air, natural gas co-firing and installing a carbon bed for BTEX removal. Unfortunately none of the options provided the cost-effective, simple-to-operate and sustainable solution required.”

To enhance the content of hydrogen sulphide in the acid gas, Shell Global Solutions and Jacobs Comprimo (an authorised licensor of Sulfinol® technology) proposed using its patented, integrated, hot-flash-enrichment gas-treating scheme, which uses Sulfinol-M.

Acid gas enrichment processes are used to increase the acid gas’s hydrogen sulphide concentration and alleviate the problems associated with a lean acid gas feed to the sulphur recovery unit. With a conventional acid gas enrichment unit, it is impossible to achieve high sulphur recovery when carbonyl sulphide, carbon disulphide and mercaptans are present because the selective treating solvents commonly used do not absorb them. Consequently, these organic sulphur species slip to the incinerator, thereby increasing the sulphur dioxide emissions.

Sulfinol-M’s formulation (methyl diethanolamine, Sulfolane and water) enables it to be used for selective and non‑selective removal of hydrogen sulphide in the presence of carbon dioxide, depending on the process conditions.

In the non-selective main absorber, the Sulfinol-M absorbs the hydrogen sulphide, carbon dioxide and trace sulphur components, with the treated gas coming from the top of the absorber. In the selective enrichment section, rich solvent coming from the bottom of the main absorber via a hydrocarbon flash vessel is heated and flashed at reduced pressure.

The carbon-dioxide-rich flash vapour flows to the enrichment absorber where lean Sulfinol-M solvent preferentially absorbs hydrogen sulphide and some trace sulphur components. The enrichment absorber overhead vapour is routed to the incinerator, while the rich solvent from the enrichment absorber is combined with the flashed solvent from the hot flash and routed to the common regenerator.

The acid gas, therefore, flows from the Sulfinol-M regenerator to the sulphur recovery unit, and this has increased the concentration of the hydrogen sulphide in the acid gas to the sulphur recovery unit from 34 to 62 mol%.

“This improved the acid gas quality so much that it was possible to reduce the size of the sulphur plant by about 30%,” says de Oude. “At the same time, we could also eliminate the need to install a dedicated BTEX removal unit. In addition, the overall plant sulphur recovery improved owing to the lower sulphur species level in the flash gas routed to the incinerator.”

Furthermore, cost calculations revealed that this approach could cut the capital expenditure by up to $67 million per acid gas removal unit or sulphur recovery unit train.

“Of course, every plant is different,” de Oude concludes, “but we have numerous examples of how we can unlock substantial value by providing integrated designs. We can usually find opportunities to integrate units in order to optimise a plant’s performance and cut the required capital expenditure; it is just a matter of knowing where to look.”

For more details on Shell Global Solutions’ gas processing technologies.

For more information contact Matthijs de Oude

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