1

SULFINOL-X1 – LEVERAGING THE ADVANTAGES OF WELL-PROVEN AND ESTABLISHED TECHNOLOGIES IN A SINGLE

ACID GAS REMOVAL PROCESS

Craig Taylor Shell Global Solutions US Inc.

Houston, U.S.A.

Gerard van der Zwet, Mark Claessen, Renze Wijntje, Prashant Patil, Armin Schneider Shell Global Solutions International B.V.

Amsterdam, The Netherlands ABSTRACT Gas development projects face growing challenges from increasingly contaminated resources, tightening sales specifications and tighter environmental emissions. CO2, H2S, H2O, COS, mercaptans and other organic sulfur compounds will generally have to be removed from the gas prior to gas sale or liquefaction. This may result in complicated treating process schemes, often requiring a combination of processes. Ample scope exists for simplification of the process line-up, through technology development as well as smart integration of the different process steps. A key element in these schemes is the Acid Gas Removal Unit, which traditionally relies on amine based solvent absorption. Sulfinol-X is presented as a technology development based on long-term design and operational experience with both traditional hybrid solvents such as Sulfinol-D and accelerated MDEA solvents. Sulfinol-X technology offers a number of advantages over more traditional solvents. Several case studies are presented showing the potential benefits of Sulfinol-X technology, both for revamps of existing plants as well as design of new plants. Benefits include increased capacity, reduction of energy consumption, lower chemicals consumption and waste disposal, tighter CO2, H2S and COS specifications and simplified process schemes. For new plants the case demonstrates that simplicity and reliability can be realized by employing the Sulfinol-X technology, while reducing CAPEX significantly compared to traditional accelerated MDEA schemes for highly contaminated gases. Finally, two examples are presented of facilities which utilize the Sulfinol-X technology, demonstrating the predicted advantages and long term stability of the new solvent.

1 Sulfinol is a Shell Trade Mark

2

1. Introduction The production, processing and use of natural gas is well established in industry, providing a clean, reliable, safe and secure energy source. Gas development projects have evolved, from the simple exploitation of sweet gas reserves directly into domestic and industrial supply networks, to exploitation of remote gas deposits through liquefaction, marine transport and regasification. Gas to Liquids technology allows the clean properties of natural gas to be utilized in a liquid form allowing the well-established infrastructure of oil products markets to aid in value generation. Contaminants in natural gas typically include CO2, H2S, H2O, mercaptans (RSH) and carbonyl sulphide (COS ). These contaminants need to be removed if they are present in quantities above the level specified for the intended application. The early gas development projects focused on exploitation of sweet gas reserves, which requires CO2 and H2O removal only and is relatively simple. A typical treating process line-up is shown in Figure 1. It consists of an Acid Gas Removal Unit (AGRU) for CO2 removal and a Dehydration Unit for drying of the gas. The individual process steps will be discussed in more detail in section 2. The acid gas from the AGRU, containing CO2 and minor amounts of hydrocarbons (HC) may be vented, incinerated, or compressed and subsequently sequestered.

AGRUAbsorber Dehydration

AGRURegenerator

NG, CO2

Solvent,HC

H2O

Venting,Incineration,Compression/Sequestration

CO2

HC

NG,

H2ONG

CO2

Figure 1 - Scheme for CO2 and H2O removal.

As sweet gas reservoirs become less available, gas development projects focus increasingly on more contaminated gas reservoirs, e.g. containing CO2, H2O, H2S, mercaptans and COS. In this case the treating process line-up becomes more complicated and often requires a combination of processes, increasing complexity and decreasing reliability. This is further amplified by tightening product specifications for sales gas and LNG (as envisaged in the new European Unity specification for natural gas) and tighter environmental emission limits. A typical process line-up in this case is shown in Figure 2. In comparison to the case of CO2 and H2O removal only, additional process steps will generally be required for removal of mercaptans (RSH) from the regeneration gas stream and recovery of H2S and other sulfur compounds from the acid gas (to be further explained in section 2).

3

AGRUAbsorber

Dehydration /MercaptanRemoval

AGRURegenerator

NG, H2S, CO2,RSH, COS

Solvent,HC

H2O

H2S, CO2,HC

NG,H2ORSH,COS

NG

S RecoveryCompression/Sequestration

H2S, CO2, RSH,

COS or S

Regen GasAbsorber

Regen GasRegenerator

NG, H2O,RSH,COSNG,

H2O Solvent,HC,RSH,COS

HC,RSH,COS

Figure 2 - Scheme for H2S, CO2, H2O, RSH and COS removal.

For such complex treating line-ups ample scope exists for simplification, through technology development as well as smart integration of the different process steps. Section 2 of this paper will deal with the different process steps. Subsequently Sulfinol-X technology is introduced in section 3, as an example of improved technology development for Acid Gas Removal Units. Several case studies are presented showing the potential benefits of Sulfinol-X technology. Finally, in section 4 two examples of Sulfinol-X applications are discussed. 2. Process steps 2.1. Acid Gas Removal Unit (AGRU) The AGRU is employed primarily for the removal of H2S and CO2. The AGRU consists of an absorption step, where acid gases are absorbed in the treating solvent and a regeneration step where the absorbed components are stripped from the solvent, providing an acid gas stream for further processing and regenerated solvent, which is returned to the absorption step. Amines (as aqueous solutions) are the most generally accepted and widely used of the many available solvents for removal of H2S and CO2 from natural gas. Typical amines used in this service are MDEA (Methyldiethanolamine), DEA (Diethanolamine), DIPA (Diisopropanolamine), DGA (Diglycolamine) and mixtures of MDEA and so called activators. A different class of solvents are the so-called ‘hybrid solvents’, which consist of a mixture of an amine and a physical component. In addition to H2S and CO2 removal, hybrid solvents can achieve significant removal of mercaptans, COS and organic sulphides. The most well-known hybrid solvent is Shell Global Solutions’ Sulfinol solvent, consisting of an aqueous mixture of the amine MDEA or DIPA and the physical component sulfolane. DIPA-based Sulfinol (referred to as ‘Sulfinol-D’) is especially

4

suitable for deep CO2 removal (down to cryogenic specifications) and COS removal (in addition to H2S and organic sulfur species), while MDEA-based Sulfinol (‘Sulfinol-M’) is more suitable for selective H2S removal (in the presence of CO2) or bulk CO2 removal. The Sulfinol technology is widely applied, currently more than 200 units are licensed. Pure physical solvents tend not to be selected for natural gas applications due to the relatively high capital cost and the high loss of hydrocarbon components through co absorption, although they can have the advantage of dehydration and acid gas removal in a single processing step. The optimum AGRU design and solvent choice is driven by the contaminant removal requirements. In the case of CO2 removal only (Figure 1), until the ‘90s solvents based on secondary amines such as DEA and Sulfinol-D were commonly applied. Later, “accelerated” or “formulated” MDEA solvents entered the market and are currently the state of the art class of solvents for removal of CO2 and low concentrations of H2S from gases. These solvents consist of an aqueous solution of MDEA to which an accelerator (a primary of secondary amine) is added, which results in enhanced CO2 reaction kinetics. In 2000, Shell Global Solutions introduced its own accelerated MDEA solvent using piperazine as an accelerator, known as ‘ADIP-X’. Piperazine has various advantages over other activators, making it the accelerator of choice by many companies. Since then, a number of plants have been revamped from using Sulfinol-D into using ADIP-X as a solvent. In addition several new ADIP-X designs have been licensed and started up. The operating experience of the last years has enabled Shell to optimize the design, resulting in considerably improved designs. 2.2. Dehydration/Mercaptan Removal in Mol Sieves Removal of water to moderate levels can be achieved using Glycols, which is often sufficient for pipeline gas. However, gas that is to be liquefied requires dehydration to less than 1 ppm. To achieve this, molecular sieves (‘mol sieves’) composed of Aluminosilicate zeolites are required. Some types of mol sieves are suitable to remove mercaptans as well. In a typical industrial application, gas contaminants in a low temperature gas stream adsorb onto the mol sieve. The bed operates in adsorption mode for a predetermined time, set to avoid contaminant breakthrough. After adsorption, the mol sieves are regenerated by a stream of high temperature gas (typically 10% of the flow of the process gas). This liberates the contaminants and concentrates them in the regeneration stream. Water and some hydrocarbons are knocked out on cooling the regeneration gas, while any mercaptans present remain in the gas stream. The gas is then compressed and typically recycled upstream of the mol sieve bed or AGRU. When the molecular sieve is used for mercaptans removal, recycle of mercaptans in the regeneration gas would lead to a build up in the adsorption / regeneration circuit and early mercaptan breakthrough. Therefore, a separate dedicated regeneration gas treating unit is required making use of an hybrid or pure physical solvent to remove the mercaptans from the regeneration gas stream (Figure 2).

5

Process schemes using an aqueous amine in the AGRU will require this separate dedicated gas treating unit for mercaptan removal. Due to the transient nature of the operation of the mole sieve beds, the mercaptans concentration in the regeneration gas will vary over time, and careful design of the dedicated regeneration gas treating units is required. 2.3. Acid Gas Processing The acid gases in the AGRU regenerator offgas are further processed depending on composition, environmental requirements and contaminant utilization options. The alternatives can include venting, incineration, compression and subsurface injection, or conversion and recovery of H2S as sulfur. For gas streams containing appreciable amounts of H2S and organic sulfur a sulfur recovery unit (SRU) is typically employed to produce elemental sulfur. The Claus process is the most widely used sulfur production process. Part of the H2S is first oxidized in a reactor furnace to SO2. The SO2 and remaining H2S are subsequently converted to liquid sulfur in a series of catalytic reactors. Typically 95% of the H2S is converted to sulfur. Mercaptans and COS can also be converted to elemental sulfur in a Claus unit. In addition to the Claus process, a (Claus) tail gas treating unit (e.g. SCOT) may be part of the sulfur recovery unit in order to boost the sulfur recovery efficiency to more than 99.5%. If the acid gas from the main AGRU is not sufficiently rich in H2S, the acid gas may require enrichment in a selective enrichment AGRU prior to feeding to the SRU. Transients in mol sieve regen gas concentration (mercaptans, hydrocarbons, COS and CO2) directly translate (via the regen gas absorber / regenerator) to transients in the composition of the acid gas being fed to the sulfur recovery unit (Figure 2). These transients require rapid changes in the oxygen demand in the Claus unit to maintain the correct stoichiometric ratios. A tail gas analyser downstream of the last catalytic stage in the Claus unit controls the stoichiometry. Due to the residence time in the Claus unit, there is a control lag that makes it difficult to correct the air flow in response to large and rapid changes in air demand. Mercaptans and hydrocarbons require more air per mol than H2S to maintain the correct stoichiometry, hence the presence of these components in highly varying quantity increase the risk of running far from the required stoichiometry. Doing so has the consequence of reduced sulfur recovery efficiency, insufficient conversion of hydrocarbons and mercaptans leading to soot formation, catalyst blockage / deactivation and off spec sulfur. Therefore, from an operational point of view, transient flow of contaminants to the Claus unit should be avoided as it increases the complexity and operators attendance.

6

3. Sulfinol-X technology 3.1. Introduction Sulfinol-X2 is a technology development based on long-term design and operational experience with both traditional hybrid solvents (e.g. Sulfinol-D) and piperazine accelerated MDEA solvents (e.g. ADIP-X). While accelerated MDEA solvents are state of the art for standard treating requirements (e.g. CO2 removal only, low concentrations of H2S), for projects that require removal of considerable amounts of trace sulfur components, the following disadvantages of accelerated MDEA based technology solutions can be identified: • Additional complexity (molecular sieve, molecular sieve regeneration gas treating

unit, transient flows to SRU, etc. – see Figure 2). • Hydrocarbon losses due to molecular sieve regeneration gas treating using physical

solvents.

Project evaluations in the past have shown that, in specific circumstances, the advantages of accelerated MDEA based technology solutions for deep removal of contaminated gases over traditional hybrid solvents resulted in the selection of these complex MDEA based schemes. Within Shell Global Solutions, the drive for reliability, robustness and simplification resulted in the development of a second-generation hybrid solvent. This solvent comprises of a mixture of MDEA, piperazine and sulfolane, thus leveraging the advantages of well-proven and established technologies in a single acid gas removal process. The specific advantages of Sulfinol-X over the first generation hybrid solvents (specifically Sulfinol-D) are explained below. Trace sulfur removal rates With respect to mercaptans removal, Sulfinol-D and Sulfinol-X have comparable performance, which is determined by the sulfolane concentration and the solvent circulation rate. However, the COS removal capacity of Sulfinol-X versus Sulfinol-D is considerably increased. This can be contributed to the enhanced COS reaction kinetics due to the presence of piperazine. This has been demonstrated in the pilot plant experiments shown in Table 1. In these experiments, the different solvents are compared with regards to the solvent circulation at which breakthrough of COS to the treated gas occurs. The feed contains CO2 and H2S and up to 1000 ppmv of COS, at 40 bara. In the pilot plant tests the solvent circulation rate was increased for Sulfinol-D until COS breakthrough to the treated gas was minimal. The solvent in the pilot was then exchanged for Sulfinol-X. The solvent circulation was set at the Sulfinol-D COS breakthrough circulation rate and was reduced until COS breakthrough was observed . Under these conditions, Sulfinol-X demonstrated better COS removal capabilities than Sulfinol-D, even at 40% lower solvent circulation. In addition, the Sulfinol-X formulation contains less sulfolane than the Sulfinol-D formulation typically used for removing COS, thus also reducing the co-absorption of hydrocarbons. 2 Shell has a patent for Sulfinol-X

7

Solvent Solvent circulation rate (relative)

COS breakthrough in treated gas (ppmv)

Sulfinol-D 1 3.1 1 No breakthrough

0.8 No breakthrough Sulfinol-X 0.6 1.2

Table 1 – Pilot plant comparison of Sulfinol-X with Sulfinol-D regarding COS breakthrough versus solvent circulation rate. Feed gas contains 23mol % acid gas (CO2 and H2S) and 1000 ppmv COS at 40 bara.

Significantly reduced energy consumption The energy consumption is to a large extent influenced by two factors: solvent circulation rate and the desorption energy of CO2/H2S. Sulfinol-X has a significantly higher loading capacity than Sulfinol-D as MDEA reacts 1:1 with CO2 while DIPA reacts 2:1 with CO2. Therefore, 0.8 mol/mol rich loading of Sulfinol X can be achieved, compared to 0.4 mol/mol for Sulfinol-D. Thus at the same partial pressure of CO2, Sulfinol-X requires a lower solvent rate to remove the CO2 than Sulfinol-D does. Therefore, the sensible heat requirement is similar to accelerated MDEA solvents and significantly lower than Sulfinol-D. Furthermore, for CO2 absorption, the heat of reaction is lower with MDEA than with DIPA. The heat of reaction for the accelerator (piperazine) is higher compared to other amines. At a typical composition of accelerated MDEA, the overall heat of reaction for the accelerated MDEA is lower than that of DIPA. Thus compared to Sulfinol-D, for the same sulfolane content, Sulfinol-X requires a lower reboiler duty to strip the same amount of CO2 in the regenerator. For H2S the absorption enthalpies with MDEA and DIPA are similar. Both effects combined result in a significantly lower energy consumption compared to Sulfinol-D and comparable energy requirements as accelerated MDEA solvents.

No design requirement for a reclaimer DIPA forms oxazolidones with CO2, the formation rate depending strongly on the CO2 partial pressure. At high oxazolidone formation rates a reclaiming unit may be required to keep oxazolidone in the amine solution at acceptable levels. MDEA, sulfolane and piperazine have been used extensively in the industry and are known to be stable in the presence of CO2 with regards to formation of oxazolidone-like species. Therefore, no dedicated reclaimer needs to be installed for Sulfinol-X units. As with other MDEA-based solvents, feed gas contaminants (e.g. oxygen, corrosion inhibitors) might influence the degradation behavior, therefore proper design of the upstream separation unit is essential.

Reduced hydrocarbon co-absorption At comparable sulfolane concentration and solvent circulation rate, both Sulfinol-D and Sulfinol-X will have the same degree of hydrocarbon co-absorption. However, in case the design solvent circulation rate is determined by removal of COS, CO2 or H2S, Sulfinol-X will require a lower solvent circulation rate and therefore have significantly lower hydrocarbon co-absorption.

8

Thus, the Sulfinol-X solvent has considerable advantages compared to Sulfinol-D. Table 2 below summarizes the differences in performance characteristics of the two solvents. Parameter Sulfinol-D Sulfinol-X

Chemical composition A hybrid solvent with a mixture of sulfolane (physical) and DIPA, a secondary alkanolamine

A hybrid solvent with a mixture of sulfolane (physical solvent), tertiary amine MDEA and accelerator DEDA (piperazine)

CO2 removal Higher CO2 removal rate due to enhanced reaction kinetics, similar to ADIP-X

COS removal Higher COS removal rate due to enhanced reaction kinetics

Loading capacity / solvent circulation

Higher loading capacity (especially for high CO2 containing gases), resulting in lower solvent circulation

Hydrocarbon co-absorption

Lower hydrocarbon co-absorption, if the design is determined by removal of COS, CO2 or H2S

Solvent degradation Oxazolidone formation No oxazolidone formation Steam requirement Lower steam requirement, due

to lower solvent circulation and lower heat of reaction

Table 2 – Differences in performance characteristics of Sulfinol-D and Sulfinol-X. 3.2. Potential of Sulfinol-X technology and recent project experience Shell Global Solutions has been requested to perform several evaluations of Sulfinol-X technology, both for revamps (solvent swaps) of existing plants to increase capacity as well as for the design of new plants. Two typical cases have been summarized below. 3.2.1. Solvent swap from Sulfinol-D to Sulfinol-X in an existing plant For solvent swaps, focus is on minimizing equipment changes. A study for a plant in the Americas has investigated a potential swap from Sulfinol-D to Sulfinol-X. The requirements for the swap were: • No equipment changes. • No additional impact on the planned maintenance shut-down. The feed gas contained significant amounts of mercaptans and COS, which were a determining factor in the original Sulfinol-D design. The performance comparison of Sulfinol-D and Sulfinol-X is given below in Table 3.

9

Sulfinol-D Sulfinol-X Solvent Circulation (-)

100 % 100 %

Gas Flow (-)

100 % 131 %

Lean solvent temperature (°C)

45 45

H2S (ppmv) <1 <1 Total S (ppmv)

<16 <16

Specification CO2 in treated gas (ppmv)

<250 <250

Table 3 – Solvent swap from Sulfinol-D to Sulfinol-X.

Due to the higher loading capacity of Sulfinol-X and the enhanced COS reaction kinetics, the higher loading capacity of the Sulfinol-X solvent could be fully utilized resulting in a significantly higher gas throughput with the same solvent circulation rate and reboiler duty. A solvent swap to Sulfinol-X could also be interesting for operating companies currently using Sulfinol-D and looking for: • Reduction of energy consumption. • Lower chemicals consumption and waste disposal. • Tighter CO2, H2S and COS specifications at equal gas throughput. Detailed studies are required to determine the best Sulfinol-X formulation and to determine the benefits. Shell Global Solutions has dedicated tools to determine these benefits and guarantee the performance. 3.2.2. Sulfinol-X in a new plant For an LNG project in the Middle East, a third party performed a process comparison between an accelerated MDEA scheme (as in Figure 2) and a Sulfinol-X based scheme, for a gas containing H2S, CO2, COS and mercaptans. With Sulfinol-X mercaptans will be removed in the AGRU, thus resulting in a much smaller mol sieve unit. In addition, there is no need for a separate regen gas treating unit as the regen gas stream contains only a minor amount of mercaptans and can be recycled back to the main absorber of the

10

AGRU. The resulting scheme is shown in Figure 3. Comparison with Figure 2 shows that the use of Sulfinol-X technology results in a much simpler process scheme.

Sulfinol-XAbsorber Dehydration

Sulfinol-XRegenerator

NG, H2S, CO2,RSH, COS

Solvent,HC

H2O

S recoveryCompression/Sequestration

H2S, CO2, RSH,COS, HC

H2ONG

RSH, COS, or S

NG, H2O

NG,

H2S, CO2,

Figure 3 – Scheme for H2S, CO2, H2O, RSH and COS removal using Sulfinol-X technology. The Sulfinol-X line up showed significant capital cost savings (> 200 million USD for a LNG train of regular size). The study showed furthermore that the Sulfinol-X unit required a higher energy consumption compared to an accelerated MDEA unit. However, if one considers the overall scheme, the energy consumption of both schemes was comparable. As the study was done for an offshore location, the benefit with respect to reduced plot size, reduced complexity and overall process performance of the Sulfinol-X scheme, resulted in the third party recommending the Sulfinol-X scheme. 4. Applications of Sulfinol-X technology There are two facilities currently utilizing the Sulfinol-X technology, both obtained via make-up (no shutdowns) from Sulfinol-D solvent. 4.1. Plant 1 Plant 1 has an AGRU treating a natural gas stream to remove CO2 and H2S upstream of a cryogenic LPG recovery facility and an ethane/propane recovery unit. The feed gas exiting the slug catcher passes through a vertical demister knock out vessel with the potential for hydrocarbon entrainment into the AGRU. The plant was originally designed for and operated with the Sulfinol-D solvent. In 2005, the plant experienced significant foaming issues, which were causing costly capacity reductions. The foaming was due to significant amounts of liquid hydrocarbon build up and operation with a low solvent inventory. The solvent inventory was increased by adding MDEA and Piperazine as an immediate remedial measure, which resulted in a partial swap to Sulfinol-X solvent. This increased the solvent inventory, helped resolve the foaming problems, and provided significantly increased gas processing capacity as an additional benefit.

11

4.2. Plant 2 This plant has an AGRU servicing a hydrogen manufacturing unit which was designed for Sulfinol-D. In order to enhance the CO2 removal capacity, the solvent was swapped to ADIP-X ‘on the fly’. During the swap, the plant operated for some time at a solvent composition similar to Sulfinol-X. The plant operated stable and the performance and capacity increase were in line with the predictions. 5. Conclusions As sweet gas reservoirs become less available, current gas development projects focus on more contaminated gas reservoirs containing CO2, H2O, H2S, mercaptans and COS. Removal of these components require complex treating process schemes using special combinations of processes. Sulfinol-X is a technology development based on long-term design and operational experience with both traditional hybrid solvents such as Sulfinol-D and accelerated MDEA solvents. Sulfinol-X is suitable for removal of H2S, CO2, mercaptans, COS and organic sulfides and can be applied to new designs as well as revamping of existing plants to increase capacity, reduce energy consumption, lower chemicals consumption/waste disposal and achieve tighter CO2, H2S and COS specifications. Gas treating schemes with Sulfinol-X in the Acid Gas Removal Unit will significantly simplify the process scheme, remove the need for a dedicated gas treating unit for mercaptan removal from the regeneration gas and eliminate the impact to the SRU by the transient nature of the molecular sieve units.