The Technologies Being Deployed To Manage Complex And Contaminated Gas On Major Projects In Indonesia
The Indonesian government has stepped up its gas projects as it strives to meet the increasing needs of the country for both the commercial and domestic demand. Each of its projects presents specific technical challenges but one constant is the pressure to accelerate the time to start-up while processing complex contaminants.
Here we focus on three projects that provide interesting case studies on using technology to manage complex and contaminated gas, and how adopting a different approach during front-end development can help to accelerate the schedule.
Although Indonesia has historically been a significant exporter of gas, domestic energy demand is growing rapidly and the country is forecast to become a net importer in the next few years unless it develops new gas assets. Fortunately, it enjoys huge untapped natural gas reserves, so the Indonesian government is fast-tracking the development of additional natural gas resources.
One of these is the development of the Jambaran–Tiung Biru project in Central and East Java, which is a joint venture between PT Pertamina EP Cepu, Mobil Cepu Ltd and local government. This initiative is the country’s biggest onshore associated gas project and is said to involve some 1.2 trillion cubic feet of natural gas and 18.6 million barrels of condensate.
The complex composition of the gas, however, presents significant challenges. It has extremely high levels of carbon dioxide (33–40 vol%), high levels of hydrogen sulphide, and significant levels of contaminants such as mercaptans, carbonyl sulphide and aromatics.
Nevertheless, by working with Shell Global Solutions, the operator, PT Pertamina EP Cepu, has been able to develop a processing scheme that can cost-effectively handle these contaminants.
Moreover, the project teams were able to accelerate the schedule, as Derek Ritchie, Technology Commercialisation and Licensing Manager, Shell Global Solutions, explains.
“When we begin working with a customer, we are always keen to understand their underlying business objectives and here it quickly became clear that schedule was a strategic priority,” he says. “Working with PT Pertamina EP Cepu, we identified an opportunity to compress the timeline through an alternative approach to the sequencing of activities around the project critical path.”
Essentially, this involved PT Pertamina EP Cepu committing to a technology and technology line-up earlier than is conventional so that Shell Global Solutions could start to develop a basic design and engineering package (BDEP), which is more detailed than Shell Global Solutions’ standard deliverable, a basic design package (BDP).
This meant that, on selection, the engineering, procurement and construction contractor would have significantly more mature and comprehensive information than with standard sequencing, when they would receive just a BDP. “By involving us at a very early stage of the discussion when they were still brainstorming how to do the project, PT Pertamina EP Cepu has been able to fast-track the schedule by some 15 weeks,” says Ritchie.
The solution that the project teams developed involves a complex, integrated line-up of multiple licensed technologies. Shell Global Solutions has licensed the acid gas removal unit (AGRU), sulphur removal unit (SRU), hydrogenation section of the tail-gas treating unit (TGTU) and sulphur degasser, while another licensor has provided the acid-gas enrichment unit (AGEU) and the solvent side of the TGTU. “On other projects, we have licensed the entire gas-treating block, but this job demonstrates that we also have the flexibility and willingness to co-operate with our clients’ requirements. We worked very compliantly with them,” says Ritchie.
The AGRU removes most of the hydrogen sulphide and carbon dioxide from the feed gas. In addition, because the Jambaran–Tiung Biru scheme uses Sulfinol-X* technology, mercaptans, carbonyl sulphide and other sulphur species are also removed to meet required specifications in the AGRU. This all-in-one removal of contaminants can create substantial value, as it can help to reduce capital and operating expenditure; for more on this, see box “How Sulfinol-X enables process line-up simplification”.
After the AGRU, the lean acid gas is routed to the AGEU, which enriches the acid gas to enable the stable operation of the SRU. In the SRU and TGTU, the sulphur-containing components are converted into liquid elemental sulphur and the hydrocarbons in the feed are converted to carbon dioxide and water. More than 98% of the sulphur in the feed gas is converted to elemental sulphur and is brought to the hydrogen sulphide specification in the sulphur degassing unit.
Together with the off-gases from the AGEU and TGTU (which are rich in carbon dioxide), any residual sulphur compounds not recovered in the SRU/ TGTU are oxidised to convert them to sulphur dioxide. This occurs in a thermal oxidiser operating at a sufficiently high temperature to also ensure the destruction of the remaining aromatic hydrocarbon compounds, ethylbenzene and xylene, and to oxidise the carbon monoxide completely to carbon dioxide.
Different circumstances, different technologies
A few hundred kilometres away in Central Sulawesi, PT Pertamina EP (100% Pertamina) is developing another major onshore Indonesian gas development called PPGM Donggi. Here, the project team adopted a similar approach to their counterparts at Jambaran–Tiung Biru to compress the schedule. Early selection of the technology again enabled Shell Global Solutions to develop the BDEP instead of the BDP to support the strategic aim of the project of reducing the schedule.
At PPGM Donggi though, because the feed gas composition is very different to that at Jambaran–Tiung Biru (it contains more hydrogen sulphide and less carbon dioxide) the processing scheme is very different. “The customer’s drivers were very similar: to manage complex, contaminated gas, minimise life-cycle costs and optimise the project timeline,” says Ritchie. “And we are using the same acid gas recovery technology, Sulfinol-X, but the sulphur recovery element is completely different.”
Here, Shell licensed the entire gas treating block, and a similar design is being used at neighbouring project PPGM Matindok. For sulphur recovery, PPGM Donggi and PPGM Matindok are both using THIOPAQ O&G, a biological desulphurisation process that integrates gas purification with sulphur recovery in one unit. The technology removes in excess of 99.9% of the hydrogen sulphide from sour gas streams and recovers it as elemental sulphur. For more on this see box “The advantages of biological desulphurisation”.
Each of the three projects discussed in this article are progressing well and are set to begin supporting Indonesia’s strategic imperative of meeting national energy demand while also raising state revenues through exports. In each case, says Ritchie, owner–licensor collaboration has been key. “Client requirements differ from project to project and from time to time, but by working closely with our counterparts, listening to their objectives, jointly developing a flexible approach to project sequencing, and deploying appropriate technology solutions, we have been able to help them to achieve their objectives.”
*Sulfinol is a Shell trademark
How Sulfinol-X enables process line-up simplification
The complex composition of the feed gas at Jambaran–Tiung Biru meant that Sulfinol-X technology could unlock substantial value, writes Gary Bowerbank, Senior Gas Treating and Sulphur Recovery Technologist at Shell Global Solutions.
The feed gas contains high levels of mercaptans, which our solvent can treat while also removing the carbon dioxide and the hydrogen sulphide. This enables the line-up to be significantly simplified. The alternatives would be to use molecular sieves downstream for mercaptans removal or a caustic-based process, which adds complexity and cost to a project.
Sulfinol-X is interesting because it is a hybrid technology; it is not solely a physical or a chemical solvent. The inclusion of the physical component is key because it overcomes the key limitation of physical solvents: high loss of hydrocarbon components through co-absorption.
And, not only does this hybrid solvent enable the hydrocarbon co-absorption losses to be minimised, but, at Jambaran–Tiung Biru, any hydrocarbons that are “lost” are actually consumed within the thermal oxidiser, which minimises the use of valuable sales gas. So, the hydrocarbon losses are no different than if they had used a solvent that had no hydrocarbon co-absorption.”
The advantages of biological desulphurisation
Because the THIOPAQ O&G process uses naturally occurring bacteria to oxidise the hydrogen sulphide to elemental sulphur, it can deliver distinct advantages at PPGM Donggi and PPGM Matindok, writes Derek Ritchie, Technology Commercialisation Manager, Shell Global Solutions.
“Although the conventional Claus/SCOT* (Shell Claus off-gas treating) technology is the one most commonly applied for sulphur removal, THIOPAQ O&G is playing an increasing role.
“One reason for this is that it is typically much less capital intensive. This is because a THIOPAQ O&G plant (which comprises an absorption section, an optional flash vessel, a reactor section and a sulphur recovery section) can replace the amine unit, SRU, TGTU, incinerator and degasser that may be required in a typical process line-up. Moreover, costly equipment items such as burners, refractory-lined equipment and reboilers are unnecessary.
“It is relatively inexpensive to operate, too, because the expensive chemicals required for liquid redox processes are unnecessary: only sodium hydroxide and nutrients are required.
“There are many other benefits. For instance, because the biologically produced sulphur is hydrophilic, there are no plugging problems (which are often associated with redox processes), so minimal operator attention is required. Moreover, there is no free hydrogen sulphide after the bioreactor, which enhances safety.”
For more details on Shell Global Solutions’ gas processing technologies.