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An important and essential step in the reduction of global emission of greenhouse gases is the large scale application of carbon capture and storage (CCS). CCS is viewed as the required intermediate step to a less carbon intensive society. Vopak and Anthony Veder have developed a CO2 Liquid Logistics Shipping Concept (LLSC) that will provide emitters with a complete logistical transportation solution for their captured CO2 from their site to an offshore storage location. In this study the case as depicted in Figure 1 was considered.
Figure 1: Schematic of the LLSC
The LLSC will take the captured CO2 from the emitter to an intermediate storage site (i.e. Port of Rotterdam) via either barges (in liquefied phase) or pipeline (gaseous/dense phase). From this intermediate storage location (CO2 Hub or terminal) the liquid CO2 is shipped by a seagoing vessel to the permanent offshore storage sites where the ship will discharge on a standalone basis via an offshore infrastructure (e.g. turret, submersed flexible hose or loading tower) that links the vessel to an injection platform or subsea completion/template. Alternatively the ship could moor near the platform and discharge the LCO2 into the reservoir via utilities at the platform. The permanent offshore storage sites that could be applied are (almost) depleted oil or gas fields and aquifers. In addition compressed CO2 is transferred from the CO2 Hub to the storage sites by means of offshore pipelines. The CO2 Hub will combine and link pipeline systems and barging/shipping routes, and will include functions like intermediate liquid storage, liquefaction of CO2 and vaporization of liquid CO2 as required. The concept will provide maximum flexibility and reliability to both emitters and storage locations, eventually leading to reduced cost of CCS.
One of the first problems to tackle was which thermodynamics models and equation of state to use for calculating the chain’s components. It is of paramount importance to have consensus on this in order to guarantee that the parties involved in the whole chain calculate, model and simulate with the same “reality”. Discussions have led to the following definition of the ‘true thermodynamics” for CO2 throughout the transportation route:
- a Soave-Redlich-Kwong Equation of State (EOS) with the Sour option, and Lee-Kessler enthalpy method specification, named as Sour SRK-LK in the wet part of the process;
- an improved Peng-Robinson Equation of State (EOS), the Strylek and Vera modification of the Peng-Robinson equation of state with Lee-Kessler enthalpy method specification, named as PRSV-LK in the dehydrated sections of the process (after a drying unit).
At the emitter’s site drying of the CO2 has to be done prior to transportation. Depending on the required discharge pressure of the compressor the drying process could be performed halfway or after compression. The applicable drying technologies are TEG and/or mol sieve. The advantage of a mol sieve as dryer technology is that it can reach very low water levels (1 ppm), which is required for liquefaction. Full dehydration by adsorption technology at the emitter will omit the requirement for additional dehydration at the CO2 Hub resulting in an overall lower capital cost. A bull gear compressor is considered the most suitable for CO2 compression up to 100 bar. Above 100 bar pumping of the CO2 would be more optimal.
An important decision in the optimization of the LLSC is determining the operating pressure of the onshore pipeline collection network. The two options, subcritical or supercritical transport, both have advantages and disadvantages. This decision impacts both the equipment requirements at the emitter and the terminal. A high level comparison between subcritical and supercritical transport, indicated that for a local network of limited length, capital costs for the two options are comparable. For longer transportation distances to the terminal, pipeline at supercritical pressures will be more cost effective compared to subcritical pressures, since the latter will require either intermediate booster stations or extreme large pipeline sizes. In the Rotterdam area safety considerations may call for a subcritical pressure. Therefore the highest possible subcritical pressure for a buried pipeline has been selected for this study (Rotterdam min. soil temperature 5 °C): 40 bar.
Each emitter will liquefy mostly on a stand alone basis, including having its own barge terminal operation. Barges transport liquid CO2 from barge terminal at the emitter to the CO2 Hub. As more emitters join the network this system is easily extended with more stops per barge route and/or more barges travelling these routes. Also the addition of river hubs along the way to create push barge convoys as the flow grows in order to achieve additional transportation economies of scale is an option. The barges will be restricted in size due to limiting passages. An advantage of transporting by barge compared to pipeline is that they do not require as much permitting.
CO2 Hub terminal
The central point in the chain is the CO2 terminal. Influenced by multiple inlet streams and outlet streams, the terminal will be the most challenging to optimize. The storage pressure of the liquid CO2 was optimized based on the capital and operational expenditure of the equipment at the terminal. A low storage pressure was better due to decreased costs for storage tanks at the terminal, at the emitter, for the carriers and the barges. The selected storage pressure was chosen as low as possible with a margin in order to stay well away from the triple point (−55 °C) and allow some inerts in the LCO2 stream. A temperature of −50 °C has been chosen as liquefaction and storage temperature, which corresponds to a pressure of 7 bara. The liquefier successfully combines the liquefaction and pressurization for offshore pipeline transport.
LCO2 can be stored in either bullets or spheres at the terminal. Spheres with a storage volume above 2000 m3 are considered to be the most cost effective for this specific study. The final sizing of the storage capacity as well as liquefier highly depends on the case and growth scenario at hand. Although many details have to be optimized in the following stages of the development of a CO2 terminal, no major technical bottlenecks were identified.
Offshore transport could be performed by ship or by high pressure pipeline. Compression for offshore pipeline transport could be done conventionally or by compressing, liquefying and further pumping. At moderate ambient temperatures, there is no difference on power consumption between the two. The advantage of transportation and injection through a pipeline system will be the continuous operation and its insensitivity to offshore weather downtime as is experienced by a ship with offshore offloading system. However, a ship offers more flexibility with regard to sink location and transport volume compared to a pipeline. A pipeline system is preferred when distances to the injection location are relatively short (< approximately 150 km) or capacities are very large (well above 5 MTA). Also for application for EOR, the use of a pipeline might be beneficial in case that the distances between shore and offshore reservoir are relatively short, since a constant flow of CO2 is required for the service.
Ulstein Sea of Solutions (USOS) has developed two concept designs of a LCO2 ship for the GCCSI study, specifically for the transport and offshore offloading of LCO2 into existing oil/gas fields. One was based on a design with Ulstein X-bow® and the other design based on a conventional bow. The conventional-bow design performs better then the X-bow® design under the conditions of this study (i.e. mainly stationary offshore discharging). For the study an optimal LCO2 storage volume of 30,000 m3 was selected. A challenging part of the LLSC is the offshore offloading of the carrier.
Offshore offloading system
For the safe transfer of CO2 from the carrier to the injection platform an offloading system had to be selected. There are several possible offloading systems available, but the only guaranteed solution, which offers relatively low cost combined with good uptime performance for the location in the study is the Fixed Tower Single Point Mooring System (FTSPM). This is a typical solution for the location of this study, where the water depth is 26 m.
One of the challenges in this study was to determine the offloading conditions for direct injection into a reservoir. The injection conditions will change over the years, when a reservoir is filling up, the pressure in the reservoir and the wells will rise (wellhead pressure at K12B ranges from 150–400 bara) at the end of the reservoirs filling lifetime). Research institute TNO was consulted to identify potential problems during injection operation or to identify bottlenecks that will limit the operational capabilities during injection. A minimum temperature of 13°C at the reservoir inlet is required to prevent the formation of hydrates at the bottomhole. Therefore the injection temperature at K12B should be at least 0 °C at the wellhead for the proposed injection flow rate and initial reservoir pressure.
The simulations showed that some injection challenges appear during shutdown of the injection sequence. This is an important item that requires more detailed investigation regarding the wellhead temperature drop that occurs when the flow is shut off. The tubing draining into the reservoir will cause a large pressure and subsequent temperature drop at the top of the well. This can be solved by proper well design. Since CCS for a reservoir is planned typically during 1 or 2 decades after the reservoir’s hydrocarbons have been produced to its fullest, well retubing is typically mandatory from a technical lifetime perspective. This allows for the following well optimization from a CCS point of view:
- Maximization of tubing diameter: to allow the flow regime to stay in the gravity dominated regime at the highest possible injection rate, the tubing diameter shall be increased up to the maximum diameter the casing diameter allows for.
- Installing an arctic wellhead: since the tubing will drain into the reservoir when the flow stops, the liquid column, 3 km long in this study, will act as a piston creating a vacuum with subsequently a very low temperature at the top of the well. Ice formation may be prevented by carefully setting the right operational procedure but the metallurgy shall allow for temperatures down to −80 °C. This may sound extreme but oil and gas wells experience even higher temperature excursions but then upward instead of downward.
- Using a corrosion resistant tubing material to avoid water/CO2 corrosion bottomhole.
Since the CCS industry is still in its infancy, its growth rate is currently unknown. Essentially it is mainly driven by ETS policies put in place by the authorities who are required to stimulate a quadrupling of the CO2 emission price by 2025. At this price and as a results of the economy of scale then being realized via the current subsidy schemes, the CCS industry is expected to be able to stand on its own feet. However until then the future is uncertain and therefore any CCS growth scenario should accommodate cost effective organic growth: the transportation chain’s assets should be of a modularized nature and shall allow for continuous expansion while in operation, without requiring heavy upfront investments to allow for this functionality. The LLSC provides for this since it anticipated on using barges and vessel that may be redeployed on alternative routes as the system evolves while theses remain the most cost effective means of transportation up to a chain capacity of at least 5 MTA.
The LLSC consists of four transportation sections and a central terminal. CO2 transportation is to be considered as a regular infra structural with 20+ year contract durations. Pipeline system tariffs are negatively affected by short term contracts. The tariff index for the four different transportation sections were determined. The four routes are:
- Onshore pipeline
- Offshore pipeline
The influence of capacity on the selection of the preferred configuration is limited. The main conclusion is that for longer distances ship transport is preferred, both onshore as well as offshore, which holds up to a transportation quantity of at least 5 MTA. The application of barge or ship transport of liquefied CO2 is competitive to pipeline transport, not only on flexibility, but also on costs at transport distances longer than approximately 150–200 kilometers. For the specific case of injection of CO2 in depleted reservoirs in the Dutch waters of the North Sea, the majority of these fields are located between 150 to 250 kilometers from the port of Rotterdam. CO2 transport by ship to these fields would be competitive to pipeline transport with regard to costs. This also shows that the location of the terminal is an important factor in the configuration of a CO2 network.
The main conclusion of the study is that the concept is technically feasible, but still a lot of improvement and optimization of the logistics chain has to be done. The subjects that requires additional studying and engineering is the offshore offloading principle and methodology. This part of the chain is also the weakest link from a reliability perspective as a result of weather down time associated with such systems.
Furthermore, the barge/ship solution, as part of a larger CCS transportation network, offers more flexibility in terms of flow diversion and cost effective transportation chain organic growth than a pipeline solution. However, the piping solution will show a slightly higher reliability than a barge/ship solution at the expense of having less flexibility in terms of flow diversion in case of e.g. unexpected sink downtime. Most important is that in case CO2 liquefaction is performed at the emitter, it is best kept in the liquid state up to offshore injection from a cost point of view as well as for the carbon footprint.