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The use of membrane technology for removal of CO2 from natural gas streams has been around for decades, however it is still surprising how limited the application of membranes is in the gas processing industry. Membranes have found favour in some geographic regions, but mostly in the offshore sector, principally because of the significant the smaller footprint they offer vs solvent type processes. Several high capacity membrane units are installed in Asia, but mostly for bulk removal of CO2, such as Enhanced Oil Recovery projects, where membrane feed gas may contain 40% CO2 and higher. Membranes have also found a niche as an easy debottlenecking option on the front end of existing solvent type CO2 removal plants. These specific applications aside, very few operators and designers genuinely consider membrane technology for CO2 removal for the production of pipeline quality gas. Many in the industry simply do not consider membranes to be a mainstream technology, and that includes both Operators and Engineering Contractors alike, some even include membranes in the “snake oil” category believing that they don’t work, or that they are not operable over the long term in real world commercial application.
I would like to take this opportunity to challenge those views. Having personally been involved in two large scale projects where membranes were identified as the preferred CO2 removal technology, and also having managed processing facilities utilising membranes for CO2 removal with combined capacity of over 500 mmscfd treating the gas to pipeline quality, I can attest that membrane technology does work and is reliable and operable.
The first project located in Egypt, implemented from 2006 to 2009, was an expansion of an existing facility treating conventional gas with a capacity of 300 mmscfd which already utilised membranes for CO2 removal. Operations were so impressed with the operability, reliability and relatively low operating cost, that the incremental capacity to be added was mandated to include CO2 removal by membrane technology. The project installed an additional 200 mmscfd processing capacity. Click here for details of the Egypt project.
The second project located in western Canada, was progressed through the concept phase in 2014, and included a concept study where proprietary amine and membrane processes were compared for a gas plant of 1.75 Bcf/d capacity, intended to process shale gas to meet North American transmission pipeline specification. In this instance the plant based on membrane technology was shown to have the lower capital cost (35% lower), lower operating cost (19% lower), and comparable greenhouse gas emissions, and was selected as the preferred case for the project. Click here for details of the Canada project.
Of course each project is different but the above mentioned projects do confirm that membranes can be the optimal process selection for CO2 removal, given the right project drivers.
Circumstances where membranes may be the preferred technology?
Offshore projects, or other projects where site development is difficult or relatively high cost, as membrane based process plants have a smaller footprint compared to most other technologies.
Sites where construction costs are high.Membranes banks are essentially modular in design, therefore the proportion of stick building required on site is significantly lower than processing plants based on other technologies
Locations where obtaining and mixing large quantities of solvent can be difficult, or where solvent disposal may difficult and costly. Membrane plants do have a consumable component, however these are solid elements generally manufactured from polymeric material hence are easier to handle, transport and dispose
Locations where operations may be difficult e.g. due to remoteness, or climatic conditions.My experience is that membrane systems are significantly easier to operate, maintain and optimise performance when compared to a conventional solvent type processes
Feed gas streams which are essentially dry, which greatly simplifies membrane pre-treatment needs to avoid issues with liquids affecting integrity of membrane elements
Circumstances where membranes may NOT be the preferred technology?
If very low, or no GHG emissions to atmosphere are mandated.GHG emissions from a membrane plant can never really be eliminated as there will always be some slippage of hydrocarbon with the CO2 to the waste stream.Membrane technologies operate on the relative permeability between hydrocarbon components and the acid gas components.GHG emissions may not be an issue if the waste stream were to be sequestered.
Based on current technology performance capability membranes are probably never likely to be cost effective to achieve very low concentrations of CO2 levels in the product stream, such as that required for LNG feed conditioning
Where other secondary contaminates, e.g. H2S are present in feed stream at sufficiently high levels that they will not be removed to meet specification by a membrane unit designed for CO2 removal alone.H2S has a similar permeability to CO2 for most commercial membranes, consequently the reduction in H2S concentration will be proportional to that for CO2. One could either design the membranes to meet spec on the secondary contaminant, however this would over treat for CO2 removal, however this would inflate the cost of the plant, not only the membrane units, but also other associated equipment.Alternately, a secondary unit operation could be installed downstream of the membrane unit, to polish H2S to the required level in the product stream.Again, this would considered a non-optimised design, as a single unit for removing both acid gas contaminants, would in most instances be the better solution.
What are the downsides to membranes?
All acid gas and hydrocarbon components have some degree of permeability through the membrane material, and the capability to separate the undesirable components from the hydrocarbons is solely dependent on their relative permeability. Consequently, there will never be perfect separation, and some hydrocarbons will find their way to the waste steam with the CO2.If the waste stream is ultimately going to atmosphere it will more than likely require combusting in a flare or incinerator to eliminate the unburned hydrocarbon, which may also require assist gas due to the normally low heating value of membrane unit waste stream.
A membrane installation generally requires more than 1 separation stage to achieve acceptable losses when the product stream is to be pipeline quality gas, depending on feed stream CO2 and product stream specification of course.Therefore, compression is often required to return the first stage permeate stream to the plant inlet for reprocessing, or to send to other process units.The required compression power can also be high as membrane permeate side operate at very low pressures
Pre-treatment of the feed gas stream must be to a very high standard so as to eliminate liquids and particulates either of which can severely impact membrane element performance and life
Are there any other associated benefits of membrane technology?
Flexible plant configuration – membrane banks are not required to be installed in a “train” type plant configuration, where sequential unit operations are solely dedicated to each other in a process train. Instead, larger membrane installations may be connected to associated equipment, such as pre-treatment and permeate compression, by common headers. This provides significant flexibility in plant operation and maintenance, and also allows for capacities of individual equipment connected to the common headers to be optimised. Of course the remainder of plant, e.g. liquid handling/treating may still require a “trained” layout, depending on the NGL volumes to be processed with the gas feed.
Ease of operation - the operation of a membrane plant is more of a “mechanical” exercise, with the monitoring of performance of each bank of membranes (usually with online gas chromatographs) to identify sub performing banks; taking the identified bank offline, depressuring, removing the elements from the bank, testing each element individually, replacing the degraded elements and placing the membrane bank back in service. Pre-treatment may contain activated carbon or silica which does require periodic replacement, which is normally done as a planned maintenance activity. Compare this to mixing solvent, maintaining solvent quality, cleanliness and volume in an operating solvent based process, particularly in remote areas where water may be in limited supply.
Points to consider for membrane plant process performance guarantees
Losses – the extent of hydrocarbon losses from a membrane process is an input parameter to the design, and it is the Operators responsibility to set. The lower the tolerance for hydrocarbon losses the greater the membrane surface area required for processing, and the greater the compression power needs for a 2 stage installation. Hydrocarbon losses are one aspect of a membrane plant design requiring optimisation which can only be achieved by collaboration between the Operator and the membrane vendor. Losses need to include both fuel and flare, and when established for the plant design, must be included as a guarantee point in the membrane unit process performance guarantee.
Membrane life – membrane elements are a consumable and contribute to operating cost. Operating cost is therefore strongly dependent on membrane life actually achieved in operation. Element life, among other things, is also greatly dependent on composition, the extent of CO2 removal required, and performance of pre-treatment, liquids, chemicals and particulates present in the feed stream will result in membrane elements degrading more quickly. One lesson learned for me, is that having pre-treatment included in the same scope of supply as the membrane skids greatly simplifies the contractual position in the event of any process performance related issues.
Performance over time – membrane permeability declines over time, for this reason, a membrane unit typically is commissioned with space to add more elements as element performance falls through the initial decline typical of new elements. The extent of space allowed for additional elements will differ with each supplier, and also the duration of time over which membrane performance with respect to composition and capacity are to be guaranteed.
This article is not intended to promote membrane technology as the holy grail of gas processing, rather it is only to illustrate by way of my own experience, that membranes have been successfully used in large scale processing facilities producing sales gas to pipeline specification. Membranes are a mature technology, and no longer considered a technical risk to the Operator.
However, membrane technology, like most complex processing options, is propriety and the Operator is therefore heavily reliant on technology vendor knowledge and design expertise. The Operator must ensure that feed compositions, including contaminants, and process conditions are fully enveloped, to cover all possible scenarios expected to be presented as membrane feed for vendor consideration. Like other technologies membranes will not achieve design performance if actual feed gas composition or conditions different significantly from design.
There are now many vendors in the market with good project resumes in commercial gas processing eager to share the benefits of their technology, under a confidentiality agreement of course.
Improvements in membrane selectivity, permeability and durability are continually being achieved by membrane vendors, which will ultimately lead to reduced capital cost, not only for the membrane units, but also associated plant and equipment, such as permeate compression; and also reduce full lifecycle cost by reducing the cost of the membrane consumable.
Thanks for reading
Pellcon Technical Services