4.2 Offshore CO2 Transport and Storage System Components

Offshore installations adapted or newly built for CCS purposes will have many important components. Those deemed of significant interest to a CCS project in particular include:

- Pig launchers and pig receivers;

- Carbon steel pipe – high pressure liquid pipe;

- Pressure boosting pumps;

- Pre-installed pipeline tees and connection manifolds;

- Risers;

- Emergency shutdown valves;

- Seals;

- Isolation valves;

- Compressors and pumps, and

- Venting systems

4.2.1 Transporting CO2

4.2.1.1 Pig launcher at shore point and in relation to platform receiver

The design of the pig launcher vessel and receiver forming part of the CO2 transmission system should be to the appropriate standards (e.g. DNV OSF-101)75 taking into consideration the CO2 stream composition, pressure and temperature.

Pigging should mainly be for commissioning new or re-commissioning existing pipelines. Following installation or conversion of an existing pipeline to CO2 service, however, integrity of the pipelines should need to be demonstrated from time to time through the use of pipeline pigging. A new or reconditioned pipeline should need to be hydrotested to assure pressure integrity. This should be followed by a series of pigging runs needed to displace the bulk of the water. Further drying can be accomplished by using slugs of methanol between two pigs to absorb any remaining water before vacuum-drying the line and filling with dry nitrogen.

As for the reuse of an existing gas or oil pipeline, it is likely that pigging operations will be used initially to establish the baseline conditions for the pipeline. Subsequent checks for any degradation, and proof of the low impact of dry CO2 stream on the pipeline should be carried out. However, since the CO2 will be very dry, it is likely future pigging operations will be less frequent as subsea experience is obtained. Therefore, if the pig traps are not already fitted, as an option, arrangements for attaching portable pig traps can be made in the design.

Related hazards:

- Leaks

- Explosive decompression (see 4.3.3.2)

Hazard mitigation:

- Careful component design with CO2 specifically in mind, especially with respect to elastomeric material in contact with CO2, coupled with component testing at full scale and pressure. Operator training should ensure that pigging operations are possible without consequences.

4.2.1.2 Steel pipeline – high pressure liquid pipe

Projects are likely to use standard piping diameters and thicknesses, examples of which can be found in the modelling scenario given in section 3. For the purposes of CCS, the pipeline could have two different design requirements. If the intended storage complex is already pressurised above the level required to maintain CO2 as a liquid in the injection wells, then the project might opt to use high pressure liquid pipe. However, in some cases, for instance, the E.ON Hewitt Field model76, the pressure within the field would gradually be increased using gaseous CO2 in the transport system until the field pressure could support a liquid column of CO2 in the injection wells. At that time, the transport system would be converted to a higher pressure liquid pipeline. This would necessitate a pipeline designed for both operating conditions.

It is possible that the pressures in the offshore CO2 pipeline systems could be much higher than the comparable liquid onshore systems (typically <120 bar). In offshore systems, the CO2 is being pumped long distances without any easy opportunities to boost a decaying pressure along the length of the pipeline until a distribution line reaches a platform. With trunkline pressures more likely to be 150 to 250 bar, it may also be possible to inject directly into a geological formation offshore without further boosting the pressure of the CO2. Offshore boosting of CO2 pressure should be avoided if possible, as this can add considerable complexity and cost to the operation.

A number of key factors influence the safe design of offshore pipeline systems. The distance from onshore facilities to offshore storage complexes can impact the pressure and capacity which may, in turn, influence the wall thicknesses and pipeline diameters.

Where existing pipelines are being converted there are other considerations. Those pipelines that have been deployed for gas transportation are likely to be damaged the least, whereas those used for oil are likely to have incurred losses in wall thickness as a result of localised corrosion especially at the '6 o'clock' position. The condition of an export oil pipeline may vary in accordance with operational history; the concern being the extent of actual water in the stream, the period of time it has been there, and the corrosion management regime (i.e. use of chemical corrosion inhibition) put in place over the lifetime of the pipeline. Finally, many oil pipelines are not designed for the pressures needed to maintain CO2 in the liquid phase over the length of the pipeline and therefore, would be less appropriate for conversion to CO2 transport.

Hazards to offshore pipelines:

- Ships could damage pipelines by either dropping or dragging their anchors.

- Pipeline pressures offshore should begin typically higher than in onshore systems in order to avoid boosting pipeline pressure offshore. The pressure should be maintained well above the bubble point for the CO2 mixture along the entire pipeline to its furthest delivery point to avoid two-phase flow and potential hydrate formation (see 2.3.2).

Hazard mitigation:

- Burying pipelines within designated anchorages.

- Understanding where pipelines are shown on marine charts.

- Designing the pipeline system to maintain the CO2 mixture pressure well above the bubble point by using onshore booster pumps.

- Establishing protocols to restrict off-take flows whenever pressure is close to the bubble point (minimum operating pressure) at the end of each branch pipeline.

4.2.1.3 Onshore pressure booster

The transport of any high pressure fluid, including CO2 is hazardous. The degree of the hazard is, in part, related to the pressure of the fluid being transported. In the case of CO2 for CCS applications, as has already been stated, this will usually be in dense phase (i.e. liquid) and, given the temperatures involved, usually sub-supercritical. In order to reduce the risks associated with onshore pipelines, it is likely that these will be at a pressure lower than that needed for offshore transport, as described in 4.2.1.2. Onshore pressures should be above the bubble point by a margin, but this pressure should be increased at a coastal booster station before the CO2 goes offshore.

Offshore pressure boosting may also be required if there is too great a drop in pressure between an onshore booster station and the offshore storage sites, or if the delivery pressure is insufficient to inject directly into the geological structures. It will be critical to maintain the pressure downstream of an offshore booster pump significantly above the bubble point. This should avoid two-phase flow within the pump, which would cause cavitation and significant damage.

CO2 booster pumps have been specifically designed with special mechanical seals that are flooded with high pressure nitrogen. A very small portion of nitrogen leaks into the CO2 at all times keeping CO2 away from the elastomeric external seal that retains the nitrogen. This eliminates the risk of explosive decompression of the elastomeric seal when the unit is shut off and the pump pressure is allowed to decline.

Hazards:

- Pump failure from cavitation leading to a breach of the pressure containment, and an uncontrolled escape of CO2.

- Pump seal leaks due to explosive decompression.

- Inappropriate CO2 venting arrangements.

Hazard mitigation:

- Careful design with CO2 specifically in mind, coupled with component testing at full scale and pressure along with operator training should ensure that booster stations could be operated and maintained without consequences.

- Locating the booster station away from normally occupied buildings or in a well-ventilated space on an offshore platform.

4.2.1.4 Pre-installed pipeline tees and connection manifolds

Increased use of these components should give the project greater development potential; however, depending on the type of project under consideration these may or may not be included in the design. Some pipeline systems should have been pre-designed to enable connection to other oil and gas projects, and it is quite likely that future CCS operations both on- and offshore will seek to link up. Pre-installed pipeline tees and connection manifolds therefore need to be considered to facilitate these connections.

A pre-installed tee is a stub on the outside of a pipeline which is fully exposed internally to the fluid in the pipeline. The stub is followed by two installed closed ball valves in a double block and bleed configuration. The outside valve is flanged closed to protect it from the elements. The spool piece between the valves should be filled through the bleed line with methanol until such time as a future connection is made to the outside valve. The connection to a new line should be made between the pipeline tee and a connection manifold at the beginning of the new line using a 'jumper' pipeline segment. The connection manifold should be another double block and bleed valve arrangement, with a pig launcher connection included. Using this design, the two double block and bleed valves can be used to fill the 'jumper' line with methanol removing all water. The new line can then be pigged and dried as normal. Finally, the ball valves can be opened allowing dry CO2 into a new dried connecting pipeline. This is achieved without allowing water into the fluid in the main pipeline, or release of the CO2 into the seawater.

Hazards:

- Introduction of moisture: the prime concern is to be able to make these future connections without the risk of introducing any moisture, particularly seawater, into the operating pipeline system.

- Third party damage: any subsea components attached to the trunkline or installed subsea over a storage complex should be protected from fishing operations. Other potential modes of failure include items being dropped from vessels or platforms onto offshore system components, and the support structures should be designed to protect against this possibility of damage leading to possible fracture should this occur (see also, 4.4.2).

Hazard mitigation:

- Tees and connection manifolds most likely to require a 'double block and bleed' valve arrangement with a minimum of a 2" 'hot stab' so that the dead leg pipe work can be injected with methanol/glycol, and so that future connections can be made without the risk of in-leakage of any water or escape of CO2.

- Seabed components are normally surrounded by a structure and then buried in a gravel dump, profiled to permit trawl boards to slide over the top. Typical connections and offshore facilities, protection structures and components are further described in Annex D.

4.2.1.5 Offshore pipeline design expansion 'hubs and clusters'

While initial pipeline systems may be developed on a point-to-point basis for demonstration purposes, if CCS is to be a key solution for the decarbonisation of power plants and industrial facilities, newly built networks of pipelines each capable of transporting tens of millions of tonnes of CO2 per year will be required. Clusters of onshore gathering systems may be developed to bring CO2 to coastal hubs where the pressure can be boosted before pumping the liquid CO2 down a trunk line into a region of offshore depleted oil and gas fields or saline formations.

4.2.1.6 Safe design

Trunk lines of CO2 could be connected to form greater networks of CO2 that may cross national boundaries, opening up storage capacities to regions that do not have favourable geological formations for the storage of CO2. Expansion of these networks may enable the formation of loops or ring mains like those seen for the onshore gas networks that may facilitate future expansion and maintenance of the network. In developing the initial CO2 trunk lines, the means for future connectivity for both additional pipe and additional spur lines to distribute CO2 to future storage complexes should be taken into account. It also indicates the need to establish a common standard for the impurities within the CO2 stream and to design cost effectively a pipeline system capable of handling as wide a range of impurities as possible without compromising the integrity of the system. Failure to anticipate this at the design stage would inhibit the potential for such expansion without increasing the risks of moisture ingress or escape of CO2 gas.

Typical connections and offshore facilities, protection structures and components are further described in Annex D.

4.2.1.7 Protection from third party damage

Connections in the form of pipeline tees and manifolds as well as subsea injection facilities are all potential points of failure with respect to CO2 leakage. All tees, manifolds and injection facilities should be protected against third party damage.

4.2.2 Injection of CO2

CO2 may be injected into a geological formation provided the CO2 transport pipeline pressure is sufficient. In addition, it may be desirable to bring CO2 onto a platform for control purposes or to boost its pressure before injection. However, certain design considerations should be taken into account when CO2 is brought onto a platform.

4.2.2.1 Risers

'Risers' are any piping responsible for transporting the fluid between the offshore platform and the seabed.

Many oil and gas developments use flexible hoses to achieve either part or the whole of the satellite well or tie-in and often, flexible risers are deployed especially on floating production installations. It is likely that the materials used for existing systems will not be suitable for CO2 service and will need to be replaced. Flexible systems may not be suitable at all for handling CO2 at high pressure and/or remain serviceable at very low operating temperatures. Suppliers of flexible systems are currently addressing these concerns to establish what may work.

Hazards:

- Rupture: A significant area for concern is a rupture in the riser above the water line or between the low and high tide mark. Such a release may result in high concentrations of CO2 in the platform area above the break. If the contents of the riser pipe are in liquid form, the resulting pressure difference may cause an extreme temperature change which could cause embrittlement to the surrounding steel structure (see 3.3.8.4).

Hazard mitigation:

- Risers designed specifically for CO2 service.

- Protective structures around risers.

- Effective checks of structure in line with 'inspecting structure for ongoing integrity'.

4.2.2.2 Emergency shut down valve (ESDV)

The ESDV sits between the transporting pipe infrastructure and the riser to the platform. This isolation valve is a fail-safe device to ensure that a failure on a platform does not lead to the evacuation of the CO2 from the whole pipeline network. These are normally found on the seabed, just inside the defined safety zone of the platform so that they avoid zones in which ships operate lifting operations where the possibility exists for heavy items to be dropped on to pipelines beneath. This also mitigates against any structural failure of the platform (platform collapse on top of the pipeline). The ESDV is designed such that upstream failure causes the valve to close.

Hazards:

- ESDV fails to close when required to do so by loss of upstream pressure.

Hazard mitigation:

- Using ESDV designed specifically for CO2 service.

- Type testing at normal and fault conditions.

4.2.2.3 Seals

Although contained within many of the components already mentioned, special consideration should be given to seals deployed on any piece of equipment which could come into contact with liquid CO2, both onshore and offshore. Changes to the state of the CO2 as a result of a rapid pressure change, can cause the seals to burst or crack. This is called 'explosive decompression', which is discussed in more detail in 4.3.3.2.

Hazards:

- Loss of pressure or an emergency blowdown may lead to damaged components, which may fail if they are not designed for appropriate CO2 service.

- Explosive decompression can present a hazard to personnel carrying out routine maintenance or operational activities.

Hazard mitigation:

- Where an escape of CO2 cannot be tolerated, nitrogen-flooded mechanical seals have been developed to prevent seepage from taking place. These are typically applied to high pressure CO2 pumps.

- Careful design of seals and gaskets with CO2 specifically in mind, coupled with component testing at full scale and pressure, alongside operator training should ensure that equipment containing seals can be operated and maintained without the hazards associated with explosive decompression.

4.2.2.4 Compressors and pumps

Different compressors and pumps may be found on a platform or even the seabed, depending on the nature of the installation. As has been mentioned, compression issues relating to CCS projects may require additional pumping units to maintain the higher pressures required over long distances. As established in an earlier EI publication77, transporting the gas in a liquid form is most likely to be at high pressures (>100 bar) and low temperature (<31 ˚C). However, once the pressure has been boosted to form a liquid, only a small amount of supplementary pressure should be required to maintain the product in liquid phase.

If the pressure drop along an offshore pipeline is such that boosting becomes necessary, it is likely that the pumps would be located on an offshore platform. The primary reason is that the power units to supply the pumps or compressors would need to be housed above water.

Recently, new seabed compressors have been developed to work with wet acid gas applications.

Hazards:

- Blowdowns: as mentioned in 4.2.2.3, compressors may contain seals that can degrade or shatter when exposed to rapid loss of pressure.

- Pump failure leading to a breach of a pressure containment vessel, and an uncontrolled escape of CO2.

- Cavitation within a pump could destroy the internal components and lead to excessive vibration which could damage the bearings, wearing rings and seals, possibly resulting in a CO2 escape.

- Inappropriate CO2 venting arrangements.

Hazard mitigation:

- Pumps and compressors can be fitted with nitrogen-filled mechanical seals to prevent the CO2 from seeping into the elastomeric seal. The seal leaks a little higher pressure nitrogen through the mechanical seal into the CO2 stream while blanketing the external elastomeric seal, isolating it from the CO2 stream.

- Cavitation can be avoided by maintaining the inlet pressure to pump significantly above the bubble point of the CO2 mixture.

4.2.2.5 Platform isolating valves

Due to the large liquid-to-gas expansion factor of CO2, care should be taken in the design of any platform isolating valve. Engineers should be mindful of this when considering the management of pressure and expansion in CO2 systems. Figure 4.1 shows the modification required to a standard ball valve which is in CO2 service, being used to isolate a pipeline. Upon closing, the ball valve will trap a small amount of liquid CO2 within its housing. If heated, the CO2 will expand and the resulting pressure will exert a force so great that the ball valve may fail catastrophically. Cryogenic valves are designed with 'cavity pressure relief holes' so that the liquid is not trapped but can either expand back upstream into the pipeline from which it came or discharge to a safe location.

Particular care should be taken when blowing down an installation which contains CO2, because it is important that rapid depressurisation to the triple point is avoided, such that the CO2 forms a solid. Appropriate procedures, that include monitoring of the pressure during blowdown, should be established.

Figure 4.1 Design of ball valve for CO2 service

4.2.2.6 Venting

If liquid CO2 is held within a static vessel it will tend to reach an equilibrium where the vapour phase at the top of the tank is just above boiling point and the liquid phase just below; in effect, the liquid in the tank reaches its saturation point. If the pressure or temperature in the vessel is altered this equilibrium will reset. Industry tends to maintain the pressure of the vessel by drawing liquid from the bottom of the tank, thereby maintaining the vessel pressure and hence the condition of the CO2 within.

For example, it can be seen that if the pressure is rapidly reduced below 7 barg the CO2 within the tank will become solid. Blowdown should be from the liquid side of the tank (and an uninsulated length of pipe is normally provided so that heat can be absorbed from the atmosphere to boil off the CO2 to gas prior to atmospheric venting). If it is necessary to blow down the vessel to atmospheric pressure, then this should take place very slowly, so that rapid depressurisation of the gas in the vessel is prevented, and solid formation is also avoided. There is a danger that the blowdown pipe itself can become plugged with solid, and the operator, observing that no further CO2 is exiting from the pipe, could believe that the vessel is drained. As the plug warms and subsequently melts, some or all of the remnant CO2 could escape and either asphyxiate or harm personnel in the vicinity.

Venting components will be found on both the onshore and offshore sections of the product delivery system. Venting small quantities of CO2 can be carried out relatively safely, particularly in an environment where high wind speeds aid its rapid dispersion. Venting larger quantities of CO2 has the potential to lead to higher concentrations, which may appear beneath the platforms or even downwind of the deck area at sea level (for example, see 3.7.4.2).

A detailed discussion of the issues surrounding venting CO2 both onshore and offshore can be found in the document produced by E.ON as part of their FEED Study for the now abandoned Kingsnorth CCS Demonstration Project78.

Hazards associated:

- Valves not designed for liquid CO2 service can explode when trapped CO2 warms and vaporises.

- Improperly controlled blowdowns can cause solids to form and create blockages around valves and vents.

- The CO2 gas arising from a blowdown can produce high atmospheric concentrations which can be a hazard to personnel.

Hazard mitigation:

- Specify valves with vented interspaces for CO2 service at the design stage.

- Considering, in operational procedures, blowing down a vessel containing CO2 such that it is kept away from the triple point, and avoiding freezing.

- Leaving unlagged a portion of the pipework of a vent so that it can absorb heat from the atmosphere (or trace heaters can be used) on the platform where vents or release valves are present to prevent temperature falling and 'snow' forming.

- Locating vents where dispersion is likely to be at a maximum, and controlling discharge rates to avoid atmospheric concentrations that present a hazard to personnel.

75 Offshore Standard Det Norske Veritas DNV-OS-F101,Submarine Pipeline Systems October 2010

76 Kingsnorth CCS Demonstration Project - Key Knowledge Reference Book, Feb 2011, E.ON UK, Section 7.15 Technical Design – Wells and Storage; Injectivity – Refine Well Development Plan

77 Good plant design and operation for onshore carbon capture installations and onshore pipelines, Energy Institute September 2010

78 http://www.decc.gov.uk/assets/decc/11/ccs/chapter4/4.44-full-system-carbon-dioxide-relief-vent-and-blowdown-system-design-philosophy.pdf