Abstract

The development of natural gas reserves containing harder-to-remove sulphur species has increased in recent years, while sulphur limits for treated gas and stack sulphur dioxide (SO2) emissions have continued to tighten. This combination has resulted in significant increases in the complexity of acid gas removal units (AGRU) and sulphur recovery units (SRU). With standalone designs for AGRUs and SRUs, licensors may be able to optimise the process units individually. However, based on Shell’s experience as licensor and operator, additional capital and operating expenditure benefits can be realised through integrated AGRU and SRU designs.

This paper focuses on the value of integrated process line-ups aimed at:

  • creating new cost-effective modes of operation;
  • reducing plant complexity;
  • dealing with a wide range of feed gas contaminant uncertainties; and
  • meeting stringent emission requirements.

The case studies below illustrate how the above benefits can be achieved by using a structured integrated approach to gas processing designs:

  1. using a heated flash in the AGRU to create a better quality acid gas feed to the SRU;
  2. integration of AGRU/acid-gas enrichment unit (AGEU) off-gas with SRU tail gas treating (TGT) units to handle benzene, toluene, ethylbenzene and xylene (BTEX) destruction effectively in SRUs; and
  3. cascading of semi-lean solvent from the Shell Claus off-gas treating (SCOT®) absorber to the main AGRU absorber.

1.Introduction

The development of natural gas reserves containing harder-to-remove sulphur species has increased in recent years, while sulphur limits for treated gas and stack sulphur dioxide (SO2) emissions have continued to tighten. This combination has resulted in significant increases in the complexity of acid gas removal units (AGRU) and sulphur recovery units (SRU). With standalone designs for AGRUs and SRUs, licensors may be able to optimise the process units individually. However, additional benefits can be realised through an integrated design.

The key barrier to integration for many projects lies at the tendering stage. Often, invitation-to-bid (ITB) documents are issued for dedicated process items such as AGRUs or SRUs. Constrained by the terms of the ITB, bidders and licensors can only propose an ITB-compliant offer for that single unit and cannot put forward integrated, multi-unit solutions that may be more suitable for the project.

This unit-specific approach to tendering may be guided by a desire to attract multiple bidders in order to boost competition and a belief that no single licensor can offer all superior technologies that the project needs. However, this paper aims to demonstrate that an integrated approach typically outperforms non-integrated designs, and offers potentially lower capital expenditure and higher net present values (NPV).

2. Opportunities on offer

At the bidding stage, project developers should also consider the customer value proposition of integrated line-ups, provided by licensors such as Shell. Shell is amongst the very few licensors, who have extensive experience of designing and operating integrated assets. This Owner /Operator experience enables us in quantifying the value of integrated line-ups relative to combination of individual plants. Having a single supplier provides an opportunity for the vendor to optimise the whole gas processing line-up, which can result in improved net present value for the client.

Having multiple licensors for different parts of the line-up introduces the problem of each unit having several different design margins to allow for any variations in the feed at the unit battery limit. Selecting an integrated line-up through one licensor with experience and in-depth knowledge of each of its units can eliminate that problem.

This is because a vendor that is providing the entire line-up understands the parameters of each individual unit as well as how they can best work together. The vendor can, therefore, hone the design of the whole line-up to minimise design margins. This has a positive effect on equipment sizing, capital expenditure, operating costs and, ultimately, on life cycle costs.

An integrated line-up through one licensor also boosts flexibility for clients by giving them access to the licensor’s entire portfolio of technologies and to its operating experience. This can enable designs to be changed or refined even further should the project scope change after the initial tender is issued, thus minimising the impact on schedule and costs.

It typically also results in an accelerated schedule for the process design package and means the single licensor can often start work on elements of the design in parallel rather than having to wait for another licensor to finalise Package A before Package B can be started.

During the contract stage, the integrated approach can also reduce the number of interfaces required. With one vendor, there is typically only one project team on the client’s side. A reduction in project and/or technical interfaces can remove obstacles to development and reduce project schedules.

It can also be beneficial because the client only has to deal with the overall process guarantees for the whole line-up, rather than defining the battery limits for every unit with multiple licensors. This can have a knock-on effect in the operating stage if there is an issue with one of the guarantee values. In that instance, licensors may often point blame at each other leaving the operator to determine who is at fault. With one vendor, where the fault lies is much clearer and it can be rectified instantly. 

3. Financial savings

Shell Global Solutions’ experience with providing entire gas processing line-ups has proven the value of an integrated approach.

For one Middle Eastern project, Shell Global Solutions started with a contract for a single unit, but later was able to convince the client to consider an integrated design after illustrating the flexibility and value such integrated line-ups can offer. This particular project faced challenges in defining the feed gas, which meant that any bespoke line-up design might prove inadequate once more data on the feed became available.

Early data for the project showed:

  • the hydrogen sulphide to carbon dioxide (H2S/CO2) ratio in the feed ranging from 0.25 to 2.5, and likely on the lower side of the range;
  • an uncertain production profile;
  • sulphur production in the range of 500 to 2,000 t/d; and
  • uncertain levels of trace components in the feed, with no data on benzene, toluene, ethylbenzene and xylene (BTEX) and heavier alkane (C6+) concentrations.

With such uncertainty around the feedstock, Shell Global Solutions recognised an opportunity for the client to benefit from an integrated line-up. Therefore, it proposed an integrated, fixed-capacity line-up with in-built flexibility that would enable easy replication of the units, if necessary, later in the project without significant cost or schedule impacts.

Analysis showed that this fixed-capacity option’s flexibility would enable the project to progress quicker into the front-end engineering and design, and engineering, procurement and construction phases, thereby reducing the overall project schedule. A shortened timeline can bolster the net present value of a project by enabling the developer to produce oil quicker and get an earlier return on investment.

Shell’s analysis showed that, for this particular onshore sour oil and gas project, the improved net present value likely to result from using the fixed-capacity line-up would be significantly greater than the extra investment costs required during the design stage. Specifically, the design could enable the developer to avoid a project delay of one year, which could prevent about a 10% reduction in the project’s net present value, which roughly equates to a US$3 billion saving. Meanwhile, achieving this required only a relatively small additional upfront investment of US$150–250 million.

Another project in the same region saw Shell Global Solutions initially bidding on two separate units, an AGRU and an SRU, for the gas processing line-up. After securing the SRU contract, the company developed an integrated option to put to the client and found that it would result in significant savings in capital and operating expenditure (see Table 1).

Capital expenditure Non-integrated line-up Integrated line up
Capital expenditure with amine treating unit (%) 100 85
Capital expenditure withSRU-TGT (%) 100 90
Operating expenditure Non-integrated line-up Integrated line up
Steam consumption (%) 100 75
Solvent circulation (%) 100 83
Chiling duty (%) 100 95

Table 1: A comparison of the capital and operating expenditure for non-integrated and integrated gas processing line-ups for a project in the Middle East.

4. Case study 1

The first case study involves realising a reduction in capital expenditure through using a heated flash in the AGRU to create a better quality gas feed to the SRU.

For one project in the Middle East, Shell Global Solutions was invited to bid on and was selected to provide a stand-alone AGRU using its proprietary Sulfinol®-X solvent, while other licensors were selected for the SRU and TGT units. Shell Global Solutions researched some alternative configurations to determine the potential value to the client of swapping to an integrated design.

This research showed that the best available integrated line-up would involve an AGRU with heated flash using Shell Global Solutions’ Sulfinol-M solvent. This would enable the production of an acid gas of enhanced quality for the SRU. This solvent swap would come at the expense of a slightly higher solvent rate in the AGRU, but would support a reduction in the size and, therefore, the cost of the sulphur recovery and TGT end of the processing line-up.

Parameter Current, multi-licensor configuration with Sulfinol-X Alternative, Integrated configuration with Sulfinol-M and Cansol TGT unit
Treated gas CO2 content, mol% 0.003 0.3187
Acid gas to SRU, mol % Hydrocarbons (HC): 3.3
CO2: 41.77
H2S: 41.74
 
HC: 0.8
CO2: 31
H2S: 54.7
 
Air demand, % 100 76
Main combustion chamber hydraulic capacity, % 100 76

Table 2: A comparison of the client’s current, multi-licensor configuration with an optimised, integrated configuration put forward by Shell Global Solutions.

Table 2 shows that the integrated solution would result in a higher volumetric flow rate of treated gas owing to less CO2 being co-absorbed into the solvent. This would then increase revenue from the treated gas.

It also supports the argument that a smaller SRU would be required because the lower CO2 content in the acid gas from the AGRU regenerator would result in better quality feed to the SRU. CO2 takes up quite some volume in the SRU, so, by reducing that and the amount of hydrocarbons, Shell Global Solutions estimates that the hydraulic capacity required to produce the acid gas could be 20–25% lower. This could lead to 10–15% less capital expenditure by enabling a reduction in equipment size for the sulphur recovery end of the processing line-up.

In addition, the lower hydrocarbon content in the feed to the SRU main combustion chamber would also result in a lower air demand and hydraulic capacity for the SRU, and potentially better operability of the unit owing to the lower risk of soot formation caused by incomplete combustion of the hydrocarbons. 

5. Case study 2

In case study 2, an integrated approach boosted flexibility and provided access to multiple technologies. It involved the integration of AGRU/acid gas enrichment unit (AGEU) off-gas with a SRU–TGT unit.

Conventional gas processing line-ups are inadequate when dealing with difficult natural gas reserves in low SO2 emission regimes. This is especially true in the presence of organic sulphur (mercaptans (RSH) and carbonyl sulphide (COS)) and BTEX. Although bulk COS removal can be achieved using secondary amines, the removal of RSH requires hybrid solvents such as Sulfinol. In these cases, the integration of gas treating process units across the AGRU and SRU, and new breakthrough technologies are necessary to achieve optimal designs.

Shell’s novel gas processing line-ups address these challenges head-on. This particular case study highlights how, by choosing one licensor and taking an integrated approach to gas processing, developers can gain access to a wide range of options and therefore benefit from the most appropriate process design, even when handling difficult feedstock.

Shell analysts compared various integrated gas processing line-ups with more conventional options for compliance with SO2 emission requirements.

In standalone line-ups, BTEX in acid gas is handled by using the co-firing option in the SRU (Figure 1).

The preferred integrated line-up used the Shell CANSOLV® TGT+ system (Figure 2), which is an integrated sour gas treating solution that enables ultra-low SO2 emissions by capturing 99.9+% of the overall sulphur present in sour gas streams while minimising the complexity of the process line-up. This system sits at the back end of a gas processing line-up and gives operators the flexibility to capture the sulphur in off-gases and streams routed to the incinerator that would otherwise be emitted to atmosphere.

Parameter Standalone base case line-up with
fuel gas co-firing
Shell CANSOLV TGT+ unit
(improved operating window)
Relative flows downstream of Claus waste heat boiler 1.7 1.0
Relative capital expenditure 1.0 1.0

Source: Shell Analysis

Table 3: Capital cost comparison between a more conventional process line-up and the integrated Shell CANSOLV TGT+ line-up.

Table 3 clearly shows that the capital costs of the integrated, Shell CANSOLV TGT+ line-up are comparable with those for the more conventional, fuel gas co-firing line-up when processing complex contaminated reserves. The objective of sharing this data is to emphasise that the integrated, Shell CANSOLV TGT+ technology can be comparable in cost to more-traditional line-ups. However, there are significant operating expenditure benefits for the integrated Cansolv TGT+ line-up, which may result in significant NPV benefits.

Parameter Integrated option with
Shell CANSOLV TGT+ unit
Standalone base case with
fuel gas co-firing
Relative fuel gas consumption 1.0 2.1
Relative steam consumption (low-pressure steam at 3.5 barg) 1.0 1.1
Relative steam production (45 barg saturated steam) 1.0 1.2
Catalyst volume 1.0 (Claus) 1.7 (Claus)
Catalyst volume No SCOT/TGT unit catalyst SCOT/TGT unit catalyst required

Table 4: Evaluation of the various operating cost contributors comparing the integrated Shell CANSOLV TGT+ option with an integrated option using co-firing and a SCOT unit.

Table 4 shows that the Shell CANSOLV TGT+ with AGEU line-up potentially has a much lower fuel gas consumption compared with the integrated co-firing option. This is because the only fuel gas consumed in this case is by the thermal incinerator. The ability to route the flash gas to the incinerator also saves some fuel gas.

In most plants, treated gas is essentially used as fuel gas, so lower fuel gas consumption means a slight increase in product gas that can be exported or processed. Although this analysis is valid within this system boundary, the requirement to produce steam using fuel gas sometimes dominates the overall fuel gas consumption in the plant.

It is also evident from Table 4 that the Shell CANSOLV TGT+ line-up performs well in steam consumption and catalyst requirements. All three of these components make this line-up attractive from an operating cost perspective.

The benefits of the Shell CANSOLV TGT+ unit when handling difficult feedstocks are clear. Such benefits can, however, only be maximised if a customer chooses a fully integrated gas processing solution with one licensor. Early interaction between the licensor and the customer is key to ensure that the most optimum process design is uncovered.

6. Case study 3

Integration can enable a reduction in overall solvent circulation. Integration of the semi-lean solvent from the SCOT can be applied in the line up to optimise the routing of acid gas components thus reducing the required capacity of existing high pressure equipment in the line-up. The case study presented below looks at the cascading of semi-lean solvent from the SCOT unit to the main absorber.

Another example of how integration can lead to financial and performance benefits is when it enables the reuse of solvents throughout the gas processing line-up.

Shell Global Solutions is experienced in designing and operating cascaded line-ups with a SCOT absorber. In these cases, the solvent used in the SCOT absorber can be integrated with the main AGRU absorber to enable the integration of the solvent system for the whole line-up. 

To achieve this, one regenerator column regenerates the solvent before it is put through the SCOT absorber to treat the tail gas from the SRU. The amount of H2S in the SCOT absorber is, however, very limited, so the solvent is routed elsewhere midway in the main absorber to pick up more H2S. By doing that, it is possible to reduce the total amount of solvent required to treat the gas in the main absorber and, therefore, the overall solvent circulation.

Integration of the solvent systems does not affect the availability nor operability of the units in the integrated line up. Basic control loops allow the operator to adjust the routing of the semi lean solvent following changes in sour gas flow rate or sour gas composition.

Shell Global Solutions has used this integrated approach to achieve reduced solvent levels across multiple designs, and even to improve the selectivity of an integrated AGEU. Its analysis has found that an integrated solvent system can reduce solvent levels, and related utilities, by up to 20% over a line-up using separate solvent systems.

7. Access to new technologies

As previously highlighted, choosing an integrated gas processing line-up through one licensor can provide developers with access to a vendor’s entire technology portfolio, which enables them to benefit from the optimum solution for their project.

This ensures that the developer can also access the latest technology on offer. For instance, Shell Global Solutions is now developing a new solvent named JEFFTREAT ULTRA family of solvents. This highly selective solvent will be primarily used in a TGT unit in a SCOT system line-up and can help to reduce the H2S at the outlet of the absorber while still running at a lower solvent rate without the need for chilling. This makes it useful for TGT units facing issues with high ambient temperature and/or low specifications for SO2.

To reduce the SO2 emissions further, Shell Pressurised Sulphur Degasser technology can be applied. When operating the degasser at elevated pressure, the degasser vent gas containing residual H2S and sulphur mist can be routed to the inlet of the SRU rather than via the conventional route to the incinerator. Recycling the vent gas to the inlet reduces the SO2 emissions from the incinerator, as sulphur species are converted to elemental sulphur.

Access to the latest technologies such as this new solvent and the pressurised sulphur degasser is only available if developers interact with vendors during the early stages of project design and are open to an integrated approach. 

8. A track record in integration success

Shell Global Solutions has a long track record of integrating gas treating processes. For example, the company uses one solvent system at the Pernis refinery in the Netherlands, that treats all the absorbers in the refinery line-up. This includes those for SCOT unit gas, hydrocracker gas, liquefied petroleum gas and hydrotreater gas. 

Combining gas/liquid treating and sulphur recovery technologies selected from Shell Global Solutions’ wide-ranging portfolio has resulted in the successful implementation of integrated designs for several (sour) gas projects for Shell and for its clients. One example is the Pearl GTL plant in Qatar, where the full suite of Shell licensed gas processing technologies is applied in combination to ensure a robust and competitive design for the world’s largest gas-to-liquids (GTL) facility.

9. Conclusion

In conclusion, opportunities for optimisation can be lost if each process block is designed individually and not in an integrated manner. A tender that allows for integration offers the opportunity to realise such optimisation.

Some of the key values of integration in gas processing are that it potentially enables:

  • better control of SO2 emissions and an improved ability to handle fluctuations in the feed gas H2S/CO2 ratio;
  • maximisation of the synergies between units;
  • better control of design margins;
  • shorter project execution schedules; and
  • fewer interfaces to manage, i.e., single point of contact for commercial activities.

If project developers are open to an integrated approach through one licensor in the very early stages of project development, then it is possible for them to secure significant financial and practical benefits.

Based on extensive experience in licensing integrated gas processing designs, Shell Global Solutions has a consistent track record of executing integrated value-adding gas processing projects.

CANSOLV, SCOT and Sulfinol are Shell trademarks.

Pavan Chilukuri is Licensing Technical Manager with Shell Global Systems, Amsterdam, with MENA responsibilities for planning and delivering process designs that enable best-achievable NPV for gas processing blocks in upstream and downstream process configurations. He holds a MBA (strategy) from Duke University and a professional doctorate (chemical engineering) from Twente University, The Netherlands.

Anton Demmers is a Senior Process Engineer with Shell Global Systems, supporting the Shell licensing team, and is design integrator for complex gas processing third party projects. During over 30 years with Shell, he has worked in research teams studying downstream catalytic processes as well as gas treating processes mostly related to sulphur conversion processes. He studied chemical analysis in The Netherlands (University of Applied Science, HBO-B).

Copyright 2016, Society of Petroleum Engineers

This paper was prepared for presentation at the Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, UAE, 7–10 November 2016.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members.

Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

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