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May-2019

Technology selection for a natural gas plant

Selecting equipment for a sulphur block requires balancing technical performance and costs, as well as local conditions and regulations.

JAN-WILLEM HENNIPMAN and KAREN HANLON KINSBERG
Jacobs Comprimo Sulfur Solutions
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Article Summary
The configuration of acid gas treating and sulphur recovery units (the sulphur block) in a new gas plant is mainly determined by the treated gas specification and SO2 emissions specification. The treated gas specification is set by the mode of transport and application of the natural gas, for instance sales gas via pipeline, hydrocarbon recovery, liquefaction for overseas transport, or production of chemicals. SO2 emissions, on the other hand, are enforced by local authorities.

Treated gas specifications are fixed, dictated by the downstream application. But SO2 emissions, on the other hand, may be negotiable. The trend in SO2 emissions has gradually become more stringent through mandates from regulatory bodies around the world since the 1970s. It is important to acknowledge that restricting SO2 emissions was and is necessary to protect the environment from acid rain and to prevent the adverse effects of SO2 on human health. In some parts of the world, the SO2 emissions specification is heading towards 150 mg/Nm3 SO2 or ~50 ppm SO2 in the stack flue gas on a dry basis with 3% excess oxygen, previously known as the World Bank Standard (WBS).1 The World Bank is stepping back from this standard as it is phasing out the funding of fossil fuel projects after 2019.2 This level of SO2 emissions corresponds approximately with a sulphur removal efficiency (SRE) of 99.98%. This deep sulphur removal requires considerably more energy consumption compared to less stringent SREs of 99.5% or even 99.9%.

This article demonstrates how to select the optimum sulphur block configuration given a certain feed gas composition, treated gas specification and SO2 emission levels. We will also discuss how to consider CO2 emissions for each option in the technology evaluation, as a parameter for assessing the added value of ultra high recovery efficiencies, and as a parameter in the operating costs for CO2, in the context of the European Emission Trading System (EU ETS).3

Typical gas plant treating steps

The treating steps in a gas plant are mainly determined by the mode of transport to end users, via pipeline or overseas transport as liquefied natural gas (LNG). The technologies for the final polishing step depend on the end user application as fuel or to produce chemicals.4

Figure 1 provides a general overview of the different processing units within a gas plant.
The gas plant consists of the following processing steps:

Inlet receiver
Gas from the well passes first through the inlet receiver, consisting of a slug catcher to separate condensed water, hydrocarbon liquids and solids from the gas. Most gas plants also have a filter coalescer to remove any surfactants from the feed gas, which can cause issues for downstream units.

Acid gas removal unit (AGRU)
Here H2S and CO2 are removed from the raw gas, as H2S and CO2 form a weak, corrosive acid in the presence of water which can damage carbon steel piping and equipment. H2S is a very toxic gas while CO2 is non-flammable, therefore both are undesirable in large quantities in sales gas. Deep CO2 removal, typically to below 50 ppm, is required to prevent solid CO2 formation for LNG production primarily, but also for other refrigeration steps in the gas plant.

Sulphur recovery unit (SRU) and tail gas treating unit (TGTU)

If H2S is present, the following processing options are available:
• Incineration and venting to atmosphere or capturing SO2 with a caustic scrubber.
This option is only to be considered if the quantity of sulphur is below 2 t/d and the concentration of H2S in the acid gas from the AGRU is below 5000 ppm.
• Treatment using H2S scavengers: generally feasible when removing less than 500 kg per day of sulphur, which equates to ppm levels of H2S in the raw gas
• Conversion to elemental sulphur through a liquid redox process or with the Thiopaq biological process, for up to approximately 50 t/d of sulphur removal
• Recovery of pure elemental sulphur using the modified Claus process for sulphur quantities above 10 t/d
• Acid gas compression and re- injection into a suitable underground formation as a disposal method. This option is only economical for specific cases.

Dehydration and mercaptan removal
The treated gas from the AGRU is water saturated. Glycol units are typically used to achieve the necessary pipeline specification. Alternatively, molecular sieves are used in cases where cryogenic processes recover the C2+ fraction from the inlet gas, if nitrogen rejection is required, or if the natural gas product is sent to an LNG plant. Water needs to be removed to less than 0.1 ppmv to prevent hydrate formation in the cryogenic sections. Molecular sieves can also be used for mercaptan removal.

The formation of carbonyl sulphide (COS) is an important consideration when using molecular sieves for dehydration in the presence of sulphur species. COS is formed during the regeneration of the beds, and the resulting regeneration gas requires treatment using a solvent with a high affinity for mercaptans and COS. There can be different approaches to dealing with regeneration gas because of intermittent flows and varying compositions. If a treating system is in place, mercaptans and COS are then routed to the SRU for sulphur recovery. Otherwise, regeneration gas very often ends up blended with fuel gas or routed to the incinerator, depending on allowable sulphur emission levels.

Hydrocarbon liquids recovery
If the gas contains sufficient C2+ fractions, it may be economically feasible to extract these liquids, resulting in a product that may have a higher sales value than natural gas. Hydrocarbon liquid recovery might also be required to meet the heating value specifications of natural gas.

Natural gas polishing
This section covers all other processing steps necessary to meet the sales gas or LNG product specifications, for instance nitrogen rejection in cases where natural gas needs to meet a nitrogen specification, typically ranging from 3-4 vol%.

Liquid processing
The liquids from the inlet receiver are conditioned to remove any dissolved salts and to collect any hydrate inhibitors present in the raw gas. Stripping off the light components stabilises hydrocarbons from the inlet receiver. The liquids from the hydrocarbon recovery may be further processed in a natural gas liquids (NGL) fractionation train, resulting in ethane, propane, butane, and natural gasoline fractions.

Sulphur block configuration and evaluation criteria
The following are key criteria for the sulphur block when meeting natural gas specifications:
•    CO2 removal from a gas that contains no H2S
•    H2S removal from a gas that contains no CO2
•    Simultaneous removal of both CO2 and H2S
•    Selective removal of H2S from a gas that contains both CO2 and H2S.
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