Gas development projects face growing challenges from increasingly sour resources with relatively high levels of CO2, H2S, Mercaptans and COS, and tighter sales specifications and stricter environmental emission standards. The removal of trace components such as COS and RSH can have detrimental effect on project value as considerable CAPEX and OPEX investments have to be made. Predominantly mercaptans are either removed in Acid Gas Removal Unit (AGRU) with the use of hybrid solvents such as Shell's Sulfinol solvent, or slipped to downstream dehydration/mercaptan removal adsorption unit using molsieves. While the former line-up involves a single process unit to remove all sulphur compounds (H2S, RSH and COS) and CO2, the latter process line-up involves multiple process steps including an AGRU absorber with aqueous amines to remove H2S and CO2, and a molecular sieve downstream unit to dehydrate and remove mercaptans in combination with a dedicated physical or hybrid solvent for removal of mercaptans from molsieve regeneration gas. There is the perception that the use of hybrid solvents reduces revenue through hydrocarbon absorption losses. Simple hydrocarbon-loss percentages around AGRU absorber provide some insight, but this data must be used cautiously, as this data alone will not tell the full story. Previous work has shown that, in most cases, higher hydrocarbon losses through co-absorption with hybrid solvents compared with using aqueous amines such as methyl diethanolamine (MDEA) are offset by savings in reboiler energy consumption. This paper goes a step further by modelling the full life-cycle costs of the two conventionally used process line-ups so that informed solvent-selection and capital investment decisions can be made. This paper also discussed capital- and additional operating-cost savings associated with hybrid solvents, which further tip the economic balance in favour of hybrid solvent systems.
This paper demonstrates that selecting a gas processing concept that is robust against changes in predicted gas composition during the maturation of (associated) gas projects reduces the risk of schedule delays and cost creep while potentially presenting opportunities to deliver first hydrocarbons to customers earlier. During early project phases, the availability and quality of data on the specific field to be developed are usually limited. Consequently, project teams have often been left with two options when designing gas processing facilities. The first option is to rely on old data, data from well tests of questionable quality and/or data from analogue fields, if available, in order to form the basis of their design. This brings relatively high risk of having to redesign once higher quality data become available. Design alterations may delay the schedule to first oil/gas and lead to increased costs and erosion of the overall project value. The second option is to wait for new well test data to become available before starting work on the gas processing facilities. This approach, though preferable, can result in costly schedule delays and does not guarantee the delivery of accurate data on which to predict the gas composition and base the gas processing design. Appreciating this uncertainty is the first step in mitigating the risk. The second step is selecting a gas processing concept that is robust against flow and compositional deviations. In this way, the design of the gas processing facilities can go ahead at a low risk before full appraisal of the field is complete. This may enable parallel project phasing by starting the engineering procurement and construction (EPC) phase for the gas processing facilities during field appraisal. Shell believes that an effective gas processing line-up of an acid gas removal unit (AGRU) that utilises the Shell Sulfinol-X all-in-one amine technology along with a selective acid gas enrichment unit (AGEU) combined with sulphur recovery units (SRU) and sulphur dioxide (SO2) tail gas treatment provides the robustness to deal with high compositional uncertainty for the gas. The novelty in this paper is recognising that robust gas treating line-ups such as the one described above can have operational advantages and enable developers to secure their licence to operate by meeting emission restrictions. These line-ups can also have additional project execution/schedule advantages that add value to a project. Specifically, this paper will demonstrate that the small additional capital expenditure required for the proposed robust design is more than compensated for by the acceleration of the project resulting in an overall improvement to the net present value. Additional benefits to the project will be ease of operation, simplicity and ultra-low emissions.
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; andmeeting 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: using a heated flash in the AGRU to create a better quality acid gas feed to the SRU;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; andcascading of semi-lean solvent from the Shell Claus off-gas treating (SCOT®) absorber to the main AGRU absorber.
Recent Oil and Gas discoveries provide an increasing outlook of gas fields containing CO2 content between 10 mol % to as high as 70 mol % CO2. The gas needs to be treated for managing CO2 emission and to fulfil treated gas specification for sales gas or for LNG production. The increasing amount of CO2 content in newly discovered gas fields requires smart designs to minimize CAPEX/OPEX while adhering to emissions requirements. Amines and membranes are commercially available technologies for CO2 removal. However, membranes alone can only do bulk CO2 removal and cannot achieve low CO2 specifications (certainly not deep CO2 for LNG specifications). So membranes will often need an amine unit meeting the CO2 specification as a polishing step. For this paper, a case study based on amine technology will be discussed. The gas contains high CO2 (~20 mol %) which will feed a LNG plant downstream. The treated gas specification is the typical required LNG specification of 50 ppm. Amine technology is a well-proven process for CO2 removal and capable of meeting these stringent specifications, but comes with high CAPEX and OPEX at these increased levels of CO2. In this study a smart design, which involves a pioneering approach, was undertaken which enables reduction of OPEX by 30 %, and capturing a CAPEX gain of 24 % against a conventional amine design.
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