Coming out of the Ice Age

Figure 1. Typical line-up for conventional LNG plant.

Lean feed gas to LNG plants is becoming increasingly prevalent as several recent LNG projects are based on pipeline gas which contains predominantly methane with low natural gas liquid (C2-C5) and lower heavy hydrocarbons (C5+) content than typical conventional natural gas.¹ However, the leaner compositions, especially dew pointed pipeline gas, can manifest a small but significant ‘heavy tail’ of heavy hydrocarbons and BTX which can be challenging to define and remove.

Removal of heavy hydrocarbons (C8+ HHCs) and aromatic (BTX) components from natural gas prior to liquefaction is critical for continuous LNG production. Even trace concentrations of certain HHCs and aromatics can cause precipitation of solids (freezing) and fouling of main liquefaction heat exchangers. For example, even existing LNG plants supplied by relatively lean feeds or experiencing feed gas composition fluctuations often face challenges with currently installed technology to deal with trace heavies in lean feed gas.

Figure 2. Heavy hydrocarbon (HHC) removal with a scrub column inside cold box.

A lean feed gas presents many challenges to the conventional heavy hydrocarbon removal methods such as a scrub column and natural gas liquids extraction unit. The natural gas liquid extraction unit is a capital-intensive unit with a high equipment count, and it requires considerable utility demands during operation. With low yields a natural gas liquids extraction unit becomes uneconomical. The integrated scrub column may become unsuitable due to the low levels of C2-C5 components, as there is insufficient liquid traffic within the scrub column to stably operate the unit at available condensing temperatures.

In this article, a line-up study is presented comparing dual-purpose temperature swing adsorption (TSA) technology (Durasorb Cryo-HRU) to conventional processes for the removal of C8+ HHCs from lean feed gas. The analysis will highlight the benefits of the adsorption technology under specified feed gas and operating conditions. The case will be made that dual-purpose TSA technology presents significant benefits, including for dehydration retrofit applications, with regards to reduced complexity, improved CAPEX, ease and flexibility of operation, and reliability. The novelties of the technology are discussed with results from extensive testing, illustrating that the combined HHC and water removal in one system is robust. The specifications for the feed to the main cryogenic heat exchanger (MCHE) of the liquefaction unit – as referred to in this article – are summarised in Table 1.²

Conventional line-up

The analysis presented considers the various technologies for the pretreatment of lean natural gas for LNG production. Lean gas, also known as dry gas, is defined as natural gas containing less than 5% liquefiable hydrocarbons.³ The typical line-up for a conventional LNG plant with a non-lean feed gas is shown in Figure 1. After the inlet facility, the gas passes through the mercury removal unit (MRU) to remove the mercury, followed by an acid gas removal unit (AGRU) to remove the CO₂ (to <50 ppmv) and H₂S (to <3.5 ppmv), and a dehydration unit (DeHy) to remove the water (to <0.1 ppmv). An alternative option is to position the MRU downstream of the DeHy. The C5+ specification of <500 ppmv of the gas is reached in a scrub column or in the natural gas liquids section. In these steps the heavier hydrocarbons and the aromatics are removed to well below 1 ppmv.

Figure 3. Natural gas liquids turboexpander.

In a line-up with a scrub column, treated gas from the pretreatment unit is sent to the scrub column to remove HHCs using reflux generated in the liquefaction process (Figure 2). The liquid reflux consists of natural gas liquids (C2-C5) that wash down C6+ components to achieve removal of C6+ and BTX to meet specification. For lean feed gas the amount of liquid reflux is insufficient for stable operation of the column and to achieve the required specifications. A variation would be to supply external washing liquid, but in an LNG plant no suitable stream is available (i.e. the LNG is too light, and the condensate is already HHC saturated) and import of a scrubbing liquid would make the option unattractive.

A natural gas liquid extraction plant can be placed upstream of the liquefaction unit to remove natural gas liquids and HHCs (Figure 3). A natural gas liquid unit can operate at any pressure, handle wide feed variation, and remove C6+ and BTX to liquefaction specifications with low methane loss. However, this line-up is generally unattractive for lean gas as the condensate yield is too low to economically justify the CAPEX and OPEX.

Lean gas line-up options

The methods for HHC removal from lean natural gas considered in this article include the following conventional methods: addition of a TSA hydrocarbon removal unit (HRU) upstream of the DeHy unit and simple cold flash inside the liquefaction cold box. Pros and cons of both methods are described next and are compared to the newly developed BASF Durasorb Cryo-HRU technology.

An option recently made available by BASF is the addition of a HRU upstream of the DeHy unit, as depicted in Figure 4. This option offers several advantages; the Durasorb HRU targets C8+ removal to below 0.5 ppmv, considering a solubility of nC8 is <0.5 ppmv in liquid methane (at -162°C and 60 bara). The HRU also removes the bulk water, leaving a significantly lighter duty for the downstream DeHy unit that only must remove the last 50 ppmv of water. The removal of bulk water by the HRU allows for the DeHy unit to be smaller and achieve a longer bed life, in some cases up to 12 years between material change out.4 The bulk C5-C7 removal to meet the C5+ specification is achieved with a flash. Although the DeHy unit can be as much as 40% smaller, the addition of the HRU adds a regeneration system and doubles the piping and valves required for the overall system. This downside can be overlooked if the increased flexibility and reliability is considered and valued.

Figure 4. Addition of a TSA HRU upstream of the dehydration unit.

Incorporation of a cold flash inside the cold box is another method to remove HHCs (Figure 5). This is the simplest vapour-liquid separation scheme. Treated gas from the pretreatment unit is cooled by a refrigerant and expanded in the liquefaction cold box. The HHCs drop out in the liquid phase in the cold flash separator and are removed, and the lean gas is further processed. The two major drawbacks of this approach are the significant losses of methane and lighter hydrocarbons to the HHC stream, as well as the expansion of >20 bar required to achieve very deep cooling that is necessary to remove highly soluble HHCs to meet the specifications for benzene and nC8+. This process requires recompression to avoid LNG production losses. The expansion and recompression are inefficient from both a pressure management and equipment management standpoint. Furthermore, stabilisation of the HHC stream is required to meet the condensate Reid vapour pressure (RVP) specification, adding additional CAPEX.

Dual-purpose adsorption technology

The newly developed Durasorb Cryo-HRU technology from BASF is designed to be a simple and effective solution for the removal of trace HHCs from lean feed gas. Durasorb Cryo-HRU technology combines the HRU and DeHy unit functionalities into one system by utilising a multi-material approach to achieve both HHC and water removal to the required cryogenic specifications.

The configuration is similar to Figure 4, having the HRU upstream of the DeHy unit, but in the case of dual-purpose TSA, the DeHy unit is removed and replaced with the Cryo-HRU (Figure 6).

The dual-purpose adsorption unit is downstream of the AGRU, which provides the sweet gas feed to the adsorption unit. Durasorb Cryo-HRU technology is a temperature swing adsorption process, where each vessel goes through an adsorption cycle, followed by an elevated temperature regeneration cycle, followed by a cooling cycle, before going back into adsorption. The vessels operate in parallel but staggered cycles. In units where there are multiple vessels in adsorption at any given time, the outlet gas stream is combined as the product gas going to the downstream cryogenic unit.

The regeneration gas is a fraction of the treated product gas. The design uses a series heat and cool regeneration system. Therefore, regeneration gas first passes through a heated bed in a co-current (downward) direction to cool down the adsorber prior to taking it in adsorption. While doing so, the gas is pre-heated and is then sent to a regeneration gas heater to heat it up to the required regeneration temperature. Heating is performed in a counter-current (upward) direction. As the hot gas passes up through the bed it desorbs the adsorbate, takes it into the vapour phase, and carries it out of the bed. The spent regeneration gas is then cooled to condense desorbed moisture and hydrocarbons, which are collected in a three-phase regeneration gas separator. The effluent regeneration gas is then routed through a regen recycle compressor to increase its pressure, and is mixed with the sweet gas stream upstream of the sweet gas chiller. The vapour is sent back to the adsorbing tower(s). After flowing down the adsorbing bed(s), the conditioned gas is routed to the cryogenic stage.

Figure 5. Simple cold flash inside liquefaction cold box.

The majority of the adsorbent bed consists of specially developed aluminosilicate gel materials that perform bulk water removal and removal of C8+ and aromatic hydrocarbons to the cryogenic specification (Figure 7). The bottom of the bed consists of a molecular sieve material specially developed for robustness. An optional top layer can be added as a guard against carry-over from the upstream AGRU amine system. The simultaneous removal of HHCs and water in a single unit makes this approach both economical and effective, providing greater reliability and flexibility for changing feed gas conditions.

The novel aspect to the development of the dual-purpose TSA technology was the need to combine the short-cycle HRU process with the long-cycle molecular sieve dehydration process. The characteristics of the different systems are presented in Table 2. For LNG plants fed with lean gas, alternative line-ups with less capital-intensive methods for HHC removal that are tailored for the conditioning of lean feed gases must be considered. The TSA HRU technology offers many benefits compared to more conventional arrangements for HHC removal, and BASF’s TSA HRU technologies are well proven. The step-change technological advance of combining the HRU and the DeHy unit into a single, dual-purpose adsorption unit that simultaneously removes HHCs and water to cryogenic specifications, enhances the CAPEX efficiencies for new projects and provides a cost-effective retrofit option to existing plants.

BASF has decades of experience with Sorbead HRU process for pipeline conditioning applications. In these applications, the material can experience more than 10 000 cycles in a lifetime. By contrast, the typical molecular sieve dehydration unit undergoes approximately 1500 cycles in a lifetime. How can the number of cycles the molecular sieve can withstand be increased to match that of the aluminosilicate gel-based material? The main challenge for the dual-purpose technology is accelerated capacity degradation of the molecular sieves from running many more cycles than in standard molecular sieve units leading to premature breakthrough and the need for an adsorbent change-out.

Figure 6. Line-up of the dual-purpose adsorption technology for combined HHC and water removal.

Two degradation mechanisms are expected: hydrothermal ageing from increased number of regenerations and disintegration from thermal shock due to fast heating. Other degradation mechanisms (e.g. caking and coke formation) are not foreseen in this application because the molecular sieve is protected by a large layer of aluminosilicate gel and sees very ‘clean’ gas. Too fast degradation of aluminosilicate gel is not seen as a risk since Sorbead hydrocarbon dew pointing units are routinely operated with many thousands of cycles per run length.

To qualify this technology for deployment within Shell, BASF and Shell worked together to leverage the material and HRU knowledge of BASF and the dehydration unit process experience of Shell. A focused experimental programme was executed to address these potential risks.

Hydrothermal stability

BASF performed a hydrothermal ageing experiment to show the ageing profile of Durasorb HR4 under wet regeneration conditions. In this experiment, the adsorbent was exposed to a controlled steam environment at 300°C for 4000 simulated cycles, followed by a breakthrough test at various intervals during the 4000 cycles. The results showed capacity and mass transfer degradation slowing over the course of 4000 cycles (Figure 8). In other words, most of the ageing took place in the initial 2000 cycles, with minimum degradation observed after 3000 and 4000 cycles. Based on this test, the risk that the molecular sieves will lose capacity too fast in the Durasorb combined process is low, providing the molecular sieve layer is sized sufficiently in the process design. These results were consistent with BASF expectations and operational experience in Shell-advised molecular sieve natural gas dehydration service, in units that had not experienced upset or (amine) carry-over. For DeHy units in operation, it was observed that the top section of the molecular sieve bed exhibits the highest degree of decay and the decay decreases moving down the bed. A dedicated test was performed by Shell to expose molecular sieve material to low water partial pressure natural gas, representing the conditions of the bottom molecular sieve layer in the Durasorb Cryo-HRU technology. The molecular sieve material tested showed a very slow loss in adsorption capacity, totalling roughly 0.5 wt% after 1000 cycles. In conclusion, molecular sieve degradation is mainly a function of hydrothermal exposure, i.e. the capacity and kinetic degradation is slow when the materials are exposed to low water partial pressures.

Figure 7. Typical adsorbent bed configuration of BASF Durasorb technology in a dual-purpose concept.

Mechanical stability

The Durasorb Cryo-HRU technology utilises a more rapid regeneration, which requires exposing the Durasorb HR molecular sieve to full regeneration temperature gas, without the typical ramp segment, essentially shocking the molecular sieve with hot regeneration gas. To address this harsh environment experienced by the molecular sieve in the Cryo-HRU process, BASF performed a thermal shock experiment to prove the stability of Durasorb HR molecular sieves. In this experiment, the molecular sieve material underwent rapid thermal cycling in which the material was exposed to cycles of heating to 300°C then cooling to 40°C before heating again to 300°C for 5000 cycles. A propriety apparatus completed each cycle in only 150 sec. so the full 5000 cycles could be completed in a reasonable timeframe. At intervals throughout the course of 5000 cycles, the material was weighed for fines generation. At the end of 5000 cycles, essentially no fines (0.15 wt%) were observed and the water capacity was equivalent to fresh material.

Dual-purpose adsorption design

With the confirmation that the molecular sieve degradation is minimum at low water partial pressure and that thermal degradation is not taking place, the number of cycles for the molecular sieve can be extended to align with the design requirements of the dual-purpose Cryo-HRU technology. BASF achieved this target with a patent-pending bed design. Utilising BASF proprietary modelling software, the Cryo-HRU adsorption bed is designed to keep excess moisture from reaching the molecular sieve section of the bed by leveraging the water adsorption capacity of Durasorb HD aluminosilicate gel material.

Key to designing new units or working on improvements of existing plants is a deep knowledge of adsorption dynamics. Especially when cryogenic dehydration service is combined with heavy hydrocarbon removal, the understanding and simulation of multi-component adsorption is fundamental. The accuracy of simulation data to models and replicated real operating conditions using BASF’s high pressure unit (HPU) is demonstrated with the data in Figure 9. The model simulation breakthrough plot is compared to the HPU breakthrough plot for C6 and C7, showing the excellent correlation between the two. This result demonstrates the accuracy of BASF models to real conditions and highlights the precision to which BASF can design adsorption unit beds. This precision not only allows for smaller beds, it also provides clients with the confidence that the unit will operate as designed.

Once the concerns regarding molecular sieve integrity were overcome with the new bed design, the Cryo-HRU technology still required additional technological advancements to be a reliable and economical solution for simultaneous HHC and water removal for LNG pre-treatment applications. The first advance came in the form of a product development. Leveraging decades of experience using Sorbead aluminosilicate gel materials in HRU service, BASF developed a new material with 30% more capacity for HHCs compared to other commercially available products, including those of the BASF portfolio. The impact of this capacity improvement can be seen in Figure 10; at 6.2 MPa (900 psi), benzene capacity is increased with Durasorb BTX compared to commercially available material. Utilising this new material in combination with Shell’s Sulfinol amine technology for removal of BTX further improves the adsorption unit design by allowing more capacity for HHC by removal of BTX in the upstream Sulfinol unit.

In this article, the focus is on the paraffinic normal C8 isomer as this is the component with the lowest solubility in methane and the first one to deposit. However, the feed gas to LNG typically contains not only paraffinic components but it consists of a mixture of a n-paraffin with a branched-chain isomer. Since C8 is a critical component in this context, BASF carried out an experiment to compare the adsorption capacity of Durasorb HC for iC8 and nC8 components. For the test, 2,2,4-Trimethyl Pentane was considered, which is the most critical isomer as it has the lowest boiling point among the other C8 isomers. The experimental results showed the iC8 component breaking through faster than the nC8 component by 50%. For non-polar components, the boiling point is the first indication of the affinity towards the adsorbents; components with a high boiling point tend to have higher affinity. All C8 isomers have a lower boiling point than nC8, reducing the adsorption affinity leading to lower adsorption capacity towards iC8 components.

Figure 8. Molecular sieve equilibrium capacity at midpoint breakthrough.

Even though iC8 components are harder to adsorb, they are more soluble in LNG, by at least one order of magnitude compared to nC8 therefore less likely to freeze-out in cryogenic condition compared to nC8. If iC8 needs to be removed, it should be lumped into nC7 component for conservatism as it is more strongly adsorbed than nC7 but weaker compared to nC8.

Applications

The operating window of 40 - 100 bar and 15 - 55°C based on BASF experience is wide enough for LNG applications and most natural gas processing applications. Any concentration of HHCs and water can be handled by the Durasorb adsorbents, up to feed gas saturation.

In addition to providing a more economical solution for HHC removal from lean feed gas for new projects, Cryo-HRU technology is also suitable for the retrofit of existing molecular sieve dehydration units. For underperforming DeHy units or plants expecting changing feed gas composition, Cryo-HRU technology can be used and, in some cases, is more competitive than other add-on solutions. Although Durasorb Cryo-HRU technology is a drop-in adsorbent solution, modifications to the DeHy unit may be required (e.g. changing separator service from a two-phase to a three-phase).

Figure 9. Model and high-pressure unit breakthrough plot for C6 and C7.

Although the paper focused on the application of the dual-purpose Durasorb technology for achieving the water, nC8+, and BTX cryogenic specifications, the technology can also be designed to for units for which C7+ removal is the target. The required adsorbent volume (i.e. vessel dimensions or number of vessels), however, will go up. For relatively small LNG plants this could be an attractive solution, however, for larger systems the addition of the flash vessel for bulk C5-C7 removal is expected to be more cost-effective.

Figure 10. Comparison of Benzene adsorption on Sorbead vs Durasorb BTX.

Conclusions

In conclusion, BASF has developed a new, step-change technology that allows for the combined removal of heavy hydrocarbons and water to cryogenic specifications in a single unit. This technology reduces CAPEX for new projects and is suitable as a retrofit solution for running plants. The customer benefits from smaller unit footprint, reliable operations, and flexibility for changing feed gas compositions. Development of this technology required innovative bed designs to avoid pre-mature molecular sieve degradation, product development to achieve increased HHC capacity, and improved simulation tools for increased model accuracy. BASF and Shell worked together, leveraging complimentary expertise, to qualify this technology for deployment within Shell. The open and innovative mindset of Shell allowed BASF to bring the best and most effective solution to this difficult challenge. The rigorous evaluation of the Durasorb Cryo-HRU technology highlights the robustness and effectiveness of this technology.

The adapted version of BASF's article can be read in the May issue of LNG Industry magazine. Register for a free trial here.

Read the article online at: https://www.lngindustry.com/special-reports/06052021/coming-out-of-the-ice-age/