LNG is a vital energy source with tight specifications. Acid gas removal units (AGRUs) are the first step operators

take to maintain specifications and meet regulations, but they may not be enough.

Why natural gas?Power generators running on natural gas offer several advantages over oil and coal, including: lower capital costs, lower emissions and higher fuel efficiencies. Improving the gas quality ensures that the gas distributed is non-corrosive, guards against the formation of liquids or hydrates in the grids, and allows interchangeability of the gases distributed.

Consumption of natural gas is increasing, and economical transport from remote locations to an international network of power plants can be challenging. Liquefaction before transport reduces the gas volume by approximately 600 times. In addition to the remote location of gas wells, other challenges in the industry include the feed to the LNG plants being contaminated, stringent specifications and tight environmental emission limits. The tighter restrictions on

Sjaak van Veelen, MPR Services, explains how proper amine hygiene helps operators meet the specifications and regulations of LNG production.

Reprinted from March 2020

LNG feed and product quality result in tighter operational ranges.1

Gas treatment Gas treatment in LNG plants typically comprises gas reception facilities, acid gas removal, gas dehydration, mercury removal, particle filtration, heavy hydrocarbon removal and, in some cases, helium removal, because it is a valuable (by)product. The AGRU removes acid gases (CO2, H2S and other sulfur components) from the feed gas (see Figure 1).

Treated feed gas leaving the AGRU is chilled prior to entering the dryer inlet separator for the separation of any condensed hydrocarbons and water. Residual traces of water vapour are removed from the feed gas and are retained within molecular sieve dehydrators to prevent the formation of ice crystals in the gas during liquefaction.2 Traces of mercury in the feed gas, which amalgamate piping and equipment made from aluminium and aluminium compounds, are removed in the mercury removal section. After being treated, the natural gas is condensed into a liquid at close to atmospheric pressure by cooling it to approximately -162°C.

Acid gas removal Using a proprietary amine solution blend, such as accelerated MDEA and Sulfinol™ (D or X), removes acid gases. The choice of solvent will depend on process selectivity, energy requirements,

total sulfur recovery, hydrocarbon co-absorption and impact on downstream facilities.

The removal of H2S and other sulfur compounds, if any, and the removal of CO2 from natural gas before liquefaction is necessary for three main reasons:

z To meet LNG product specifications.

z To prevent the corrosion of process equipment.

z To meet environmental performance standards.

The removal of CO2 to approximately 50 ppm, safely below the solubility limit of CO2 in LNG, avoids freezing in the downstream liquefaction unit. The removal of H2S to less than 4 ppm and the removal of other sulfur components, such as light mercaptans and COS, if any, is done to meet end-user pipeline specifications.

The AGRU is an amine system with a simple design (see Figure 2).3

Feed gas enters the bottom of the absorber and makes contact with the amine solution. The amine absorbs the CO2 and sulfur contaminants from the gas in the absorber and circulates to the regeneration section. Acid gas and water vapour are stripped out leaving a lean amine solution, which is then circulated back to the absorbing section. In principle, the model is ideal; the amine solution should circulate indefinitely, performing its function flawlessly. The reality, however, is that the amine

solution becomes contaminated and operational problems occur.4

Acid gas from the AGRU, if it only contains traces of H2S, is incinerated to allow the conversion of any H2S in the gas to sulfur dioxide (SO2), and to convert any traces of methane (CH4) to CO2 before it is released into the atmosphere.

Sulfur recovery unitIn cases where the acid gas contains more than traces of H2S, it is sent to a sulfur recovery unit (SRU), which converts the sulfur components into liquid sulfur. The tail gas from the SRU that contains unrecovered sulfur is fed to the tail gas treating unit (TGTU), which is an amine system that selectively removes H2S. This can be a generic MDEA or a proprietary selective amine.

An important design parameter for the SRU is the H2S/CO2 ratio in the acid gas. If this ratio is low, an acid gas enrichment unit (AGEU) may be installed downstream of the AGRU, upstream of the SRU.5 The AGEU selectively absorbs H2S, such that the H2S/CO2 ratio of the acid gas to the SRU will be improved. It is another amine system with a specialty amine.

An LNG plant may have three types of amine systems:

z AGRU – The main amine system that removes acid gas from the natural gas.

z AGEU – To enrich the acid gas with H2S before sending it to the sulfur plant.

z TGTU – To capture the H2S from the sulfur which was not converted and bring it back to the SRU.

Figure 1. A typical LNG plant.

Figure 2. A typical amine system.

Reprinted from March 2020

Each of these amine systems can have its own operational challenges.

AGRU challengesFoaming, flooding, plugging and corrosion often cause unstable operation and failure of the AGRU to meet treated gas specifications. The root cause is often contaminants in the amine loop.

Contamination can occur due to poor liquid separation in the feed gas to the absorber. Indeed, contaminants in the feed gas (such as corrosion inhibitors), well and pipeline treating chemicals and glycol may enter the AGRU. For example, mono ethylene glycol, from the upstream hydrate inhibition, degrades under thermal conditions to glycolates, oxalates and partially to formates. The natural gas industry uses acetic and hydrochloric acids in well treatment activities. Although the concentration in the feed gas may be low, the solvent absorbs the contaminants and buildup in the closed amine loop. These heat stable salt (HSS) anions promote corrosion and the resulting corrosion products are a main cause for fouling, plugging and foaming.

Thermal degradation of the amine or the activator occurs due to hot spots in the regeneration unit reboiler, along with some oxygen. Oxygen may be from the feed gas, poor blanketing in tanks or from vapour recovery systems. As a result, formate, acetate, oxalate and amino acids due to cleavage of the amine molecules are formed. H2S with oxygen ingress will cause thiosulfates, sulfates and sulfites. Poor make-up water and cooling water leakages may lead to elevated chloride levels in the amine.

Commonly seen issues are corrosion, fouling and foaming, leading to production loss from unscheduled downtime, reduced flowrate capability, regeneration issues, increased maintenance labour and equipment costs. Corrosion products in the amine loop can settle out and accumulate in stagnant areas in the amine system, such as the lean/rich exchanger, contactor or regenerator columns. This equipment fouling can result in reboiler heat transfer loss, tray plugging in both the contactor and the regenerator, and loss of heat exchanger efficiency.

Foaming in the contactor can result in huge amine losses, reduced operating capacity, and off-spec product. Meeting a 50 ppm CO2 specification for LNG is more difficult than, for example, a 2% specification for sales gas, and minor amounts of foaming can affect removal efficiency enough to cause missed LNG specifications. Amine carried over into the sweet gas can result in fouling of downstream equipment and contamination of the downstream molecular sieve beds and may cause molecular sieve bead fractures.

Increased production and tighter product specifications lead to a greater demand on the amine plant. Purifying the amine solution on a regular basis, or even better, on a continuous basis, improves performance.

Figure 3. Corrosion in pump section.

Figure 5. Chlorides removal from accelerated MDEA system.

Figure 4. Skid mounted unit in LNG plant Indonesia.

Reprinted from March 2020

AGEU and TGTU challengesIf required, an AGEU enriches the H2S content of the acid gas stream, making it practical to recover sulfur in a Claus unit. Acid gas enrichment concentrates the H2S from the AGR system by further gas treatment in an amine unit utilising a selective amine solvent. Except for the use of the selective amine solvent, an AGEU is similar to other traditional amine treating units.

The TGTU reduces the sulfur vapour and SO2 contained in the tail gas from the SRU process to H2S and absorbs it in an amine solution. It then returns it to the SRU, thereby achieving a high rate of sulfur recovery. The amine is selective for H2S.

A typical upset in an SRU results from hydrocarbons in the acid gas from the AGRU. As a result, the air consumption control temporarily becomes erratic; SO2 breaks through and reaches the TGTU amine system where it will react with the amine to form HSSs, such as thiosulfates and sulfates. In the weeks following such a sulfur plant upset, bicine occurs in the tail gas units. Bicine has shown to contribute to corrosion and should be monitored closely. Some industry guidelines recommend that bicine does not exceed a few hundred ppm.

Case historiesThe following case histories illustrate how over the years MPR Services has been able to assist clients in the LNG industry with contamination removal.

AGRU – accelerated MDEA with bicine (degradation product)A US Gulf Coast LNG plant, utilising a specialty MDEA solvent in its AGRUs, was experiencing significant corrosion (see Figure 3) in the amine booster pumps in one of its amine trains. The plant determined that the presence of bicine, generated due to oxygen in the sour gas feed, was the cause of the corrosion. MPR Services provided its mobile HSSX® ion exchange equipment to reduce the bicine. The bicine level was reduced from 1252 ppm to 600 ppm in the operating amine system. Another chelating amino acid in the amine, hydroxyethyl sarcosine (HES) was reduced from 889 ppm down to 469 ppm. At the same time, the HSS level was reduced to 0.44 wt%. The corrosivity was reduced and the amine quality and operation improved during the job.

AGRU – accelerated MDEA with chloridesA large Indonesian LNG plant was operating for many years with a history of corrosion in its MEA trains. The plant changed to a formulated solvent, which unfortunately did not reduce the corrosion. After a second swap to another formulated accelerated amine and changing the operating parameters, the corrosion was under control.6 However, due to a cooling water incident, chlorides entered one of the AGRUs and reached a level that was high enough to potentially cause cracking corrosion of the stainless steel parts of the amine system. In response to this hazard, MPR Services rapidly deployed a mobile skid mounted unit (see Figure 4) and personnel to the site and connected to the AGRU while it kept operating. In 20 days, 2900 m³ of amine was processed and the chloride level was reduced from 1299 ppm to a very low 46 ppm, which is considered an industry safe level (see Figure 5). At the same time, the sodium level was reduced from 549 ppm down to 52 ppm. The HSS level was also

reduced from 0.88 wt% to 0.05 wt% as MDEA, which is almost fresh solvent.

AGRU in jeopardyIn an AGRU amine system (with an inventory of approximately 2300 m³) of a gas plant in the Middle East Gulf area, the concentration of heat stable amine salts, including amino acids, had increased abnormally and reached 2.35 wt%. During a corrosion coupon (CC) retrieval campaign, there was a severe thinning of strip coupons located at the bottom of the stream AGR Amine Stripper columns, installed on the lean amine lines. The results revealed a thickness reduction of more than 50%. Soon after this, corrosion was discovered in one of the two reboilers of the AGRU and needed to be repaired. The customer, who had previously worked with MPR Services, requested that a mobile reclamation job be conducted

Figure 6. Mobile containerised unit on transport.

Figure 7. HSS reduction in TGT amine unit.

Reprinted from March 2020

at the shortest possible notice. Because of the urgency, the customer chartered an Ilyushin-il-76td freight plane to bring the sophisticated mobile reclamation unit from the Netherlands to the Middle East (see Figure 6).

Within one month of processing, the HSS level was reduced to 0.31 wt%. At the same time, the bicine level was reduced from 3900 ppm down to 580 ppm, and the HES level was reduced from 3100 ppm down to 570 ppm. Most importantly, the corrosivity was reduced.

TGTU specialty amine At an LNG plant in the Middle East Gulf area, MPR Services cleaned an SRU – TGTU amine system with 1500 m³ specialty amine. MPR Services reduced the HSS and amino acids from worryingly high levels to low levels without affecting the solvents selectivity for H2S (see Figure 7). This was monitored by doing daily onsite analyses of wanted and unwanted species and H2S analyses. During the job, bicine was also reduced to safe levels.

ConclusionToday’s natural gas reserves are remotely located. As a result, the economical transportation of natural gas now relies increasingly on liquefaction. The liquefaction process requires very clean gas, therefore, the amine gas treating systems in an

LNG plant need to work flawlessly. Purifying the amine solution on a regular basis, or even better, on a continuous basis, helps operators meet the specifications and regulations of LNG production.

References1. ENGEL, D., et al, ‘Managing contaminants in LNG feed gas

and cryogenic processing Part 1’, Gas Processing & LNG, (October 2019), http://gasprocessingnews.com/features/201910/manage-contaminants-in-lng-feed-gas-and-cryogenic-processing%E2%80%94part-1.aspx

2. WorleyParsons, 'Australia Pacific LNG Project Commissioning and Start-Up Environmental Management Plan', (December 2014).

3. TAVAN, Y., et al., 'Some notes on process intensification of amine based gas sweetening process', Journal of Loss Prevention in the Process Industries, (May 2016).

4. CUMMINGS, A. L., et al., ‘Controlling Corrosion in Gas Treating Solutions’, Gas Processors Association, (February 1998).

5. BRAS, E., et al., ‘Treating difficult feed gases to LNG plants’, Shell Global Solutions International B.V., (April 2007).

6. SCHUDA, V., ‘Conversion of the gas purification system to BASF aMDEA solvent at PT. Badak NGL’, BASF Aktiengesellschaft, (July 2000).

NoteSulfinol™ is a trademark of Shell.

HSSX® is a registered servicemark of MPR Services Inc.